Goschen received Major Project status from the federal government in 2021.

A pre-feasibility study (PFS) report of Goschen project was announced in December 2021. It was followed by the completion of the Definitive Feasibility Study (DFS) in March 2022.

VHM announced the results of the DFS Refresh in March 2023, an update on the DFS, to confirm the potentiality of the project.

According to the DFS Refresh, Goschen would be a high-value, low-cost operation and produce zircon-titania Heavy Mineral Concentrate (HMC), Rare Earth Mineral Concentrate (REMC), and a Mixed Rare Earth Carbonate (MREC).

The project would have a nameplate process feed rate of 5 million tonnes per annum (Mtpa) for a foundation 20 year mine life.

It would be developed over multiple phases, with first production expected in 2025 (subject to the approvals timeline).

Around 70% of Goschen’s revenue will be generated via rare earth products such as neodymium, praseodymium, dysprosium, and terbium. These products are critical for industries such as electric vehicles, energy efficiency and technology.

Goschen Project Location

The Goschen Project is located in the Loddon Mallee Region of Victoria, around 35km southwest of Swan Hill in the Gannawarra Shire and 275km north of Melbourne.

The project is situated within Retention Lease (RL) 6806 and Exploration Licence (EL) 6419, which are held by VHM.

Mining and processing will be carried out in Area 1 and Area 3, which jointly cover around 1,534 hectares (ha).

Geology and Mineralisation

Goschen project’s heavy mineral sands are located as a fine-grained deposit within the offshore depositional paleo-environment of the Loxton Parilla Sands.

According to the DFS Refresh, alluvial sediments of the Shepparton Formation deposited over the Loxton-Parilla Sand.

Containing shallow marine clays and marls, the Bookpurnong Formation is located beneath within the lithological sequence.

There are two distinct styles of deposits- sheets and strandlines.

The sheet-style deposits, also known as Wimmera-style (WIM-style) deposits, contain relatively fine-grained heavy mineral (sub-100 micrometre (µm) with some in the 20–40µm range).

The strandline-type deposits are formed in high-energy surf zone and may attain strike lengths of 5–40km. They can contain some coarse-grained heavy minerals.

Goschen Mineral Resource Estimate

The Goschen project is estimated to contain 413,107 tonnes of total rare earth oxide (TREO).

Mineral Resource estimates and the Ore Reserve estimates are mostly based on RL 6806 with some minor incursions into surrounding VHM-held tenements.

Total ore reserves (Area 1 and Area 3) stand at 198.7 Million Tonnes (Mt). The initial operation will recover 98.8 Mt, representing around 50% of identified Ore Reserve.

The project’s total mineral resource estimate (measured, indicated, and inferred resources) of 629Mt includes areas that are excluded from current mining proposal.

Goschen Project Development

The proposed project development aims for a 20-year, 5Mtpa operation to mine and process zircon, titania, and rare earths mineral deposits.

It will be developed in three phases.

Phase 1 will include a Mining Unit Plant (MUP), Feed Preparation Plant (FPP), Wet Concentrator Plant (WCP) and a Rare Earth Mineral Flotation Circuit (REMFC) to produce Rare Earth Mineral Concentrate (REMC) and zircon-titania concentrate.

Phase 1A will introduce a hydromet circuit to further upgrade the REMC into a higher-value MREC.

Phase 2 will add another MSP to produce final mineral sand products such as ilmenite, zircon, leucoxene, and HiTi/rutile.

The project will proceed to Phase 2 if certain conditions are met including prevailing market conditions and availability of funding. However, it is not subject to the Final Investment Decision (FID) for Phase 1 and 1A.

Goschen is projected to create at least 200 construction jobs and 400 new full-time jobs.

The first phase will entail an investment of around A$376m ($245.3m) excluding ancillary cost, while Phase 1A Hydromet Circuit will cost an additional A$124m ($81m).

Based on a 20-year mine life, the project will have a pre-tax Net Present Value (NPV) of A$1.5bn ($980m). It is expected to generate a pre-tax cash flow of A$270m ($176m) per year.

VHM submitted the mining licence application to the Earth Resources Regulator (ERR) in March 2023. The application was placed on public notice in January 2024.

ERR’s review and issuance of the mining licence is contingent on the outcome of the Environment Effects Statement (EES) approvals process.

Mining Method

The rare earth project will be mined via conventional open-pit mining methods using excavator, load, and truck haulage.

Mining activity at Goschen will commence in Area 1, and then progress to Area 3. All mining will be conducted above the water table, thus ruling out the need to extract groundwater.

A strip/block mining operation will be undertaken involving excavation, tailings deposition and rehabilitation.

The mining sequence is designed to support complete extraction of ore, construction of in-pit tailings cells and deposing tailings into tailings cells.

Each of the mining blocks will be around 200m along-strike and of different widths to suit prevailing ground conditions.

The recovered ore will be loaded onto trucks and then transported to the MUP for processing.

Bulldozers and front-end loaders will also be used to support mining operations.

Processing

The ore recovery, the run of mine (RoM) will be stockpiled before sending it to the MUP via a front-end loader. It will pass through a grizzly to remove oversized pieces.

Sand and clay agglomerates will be broken down in a scrubber and the slurry will be transported to the FPP at the main processing plant.

At FPP, the sand containing the heavy minerals will be separated from clay fraction (slimes) and the deslimed, and then the screened sand will be sent to the WCP. Barren sand will be separated from the heavy minerals using spirals at WCP.

Subsequently, the heavy minerals will be directed to the REMFC. The rejected sand will be combined with the slimes and disposed back to the pit.

Coarse silicates and iron oxides will be removed from heavy minerals to improve the concentrate grade to around 92%.

A REMC (consisting mostly of the minerals xenotime and monazite) will be recovered from the HMC via flotation and gravity separation. In Phase 2, the remaining residue post flotation (P-flotation) concentrate will be directed to the wet MSP or dewatered and stockpiled as a final product.

The hydromet circuit, after commissioning in Phase 1A, will process REMC.

The final product will be loaded into bulk bags for shipping. It will be transported via road to the Ultima intermodal terminal and then by rail to the Port of Melbourne for shipment.

Infrastructure

The process plant is planned to be located on the western side of Area 1.

As mentioned, the project will include the FPP, WCP, REMFC, MSP, Hydromet Circuit, reagent storage, tailings thickener, process water dam, ancillary buildings, as well as Heavy Mineral Concentrate (HMC) and P-flotation stockpiles.

Power required for project operations will be provided by a third-party contractor using nominally 12 x 11kV high-voltage dual-fuel generators. Goschen project is expected to switch to renewable power when it becomes available.

The project is estimated to require up to 4.5 Gigalitres Per Annum (Gl/a) of water for the initial 12 months and then 3.2Gl/a later.

Water will be delivered to the Goschen site via a new 38km underground pipeline to be constructed beneath existing local road easements.

Goschen Offtake Agreement

In February 2024, VHM signed a binding offtake agreement with Shenghe Resources (Singapore), a wholly owned subsidiary of global rare earths company, Shenghe Resources Holding, regarding its Goschen Rare Earth and Mineral Sands project Phase 1 products.

The agreement will involve supplying 6,400 tonnes per annum of REMC and 100,000 tonnes of zircon/ titania HMC products for an initial three-year term.

Contractors Involved

Several independent consultants were involved with the preparation of the Goschen project DFS.

Auralia Mining Consultants carried out a mining study on the area for which VHM submitted a mining application to the Victorian government. The study was included in the March 2022 DFS.

Mineral Technologies assisted VHM with the engineering and development of the mineral processing aspects of the rare earths project.

AECOM was associated with environmental and community, power and water supply, closure, and rehabilitation, while CSA Global provided Independent technical assessment report (ITAR).

Some other firms associated include Adamas Intelligence, ANSTO, ATC Williams, BDO Australia, CDM Smith, GPA Engineering, JRHC Enterprises, pitt&sherry, Qube Holdings, and Right Solutions Australia among others.

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The field is being developed as a tie-back of the Åsgard Field.

The partners of the Åsgard Field are Equinor Energy (35.01%), Petoro (34.53%), Vår Energi (22.65%), and TotalEnergies EP Norge (7.81%).

Equinor (previously Statoil) discovered Smørbukk Nord in 2013 by drilling the well 6506/9-3 (Smørbukk Nord) on the Halten Terrace in the Norwegian Sea.

The drilling showed that the size of the discovery is between 4 and 7.5 million standard cubic metres (Sm³) of recoverable oil equivalents as per preliminary estimates.

Smørbukk Nord Location Details

The Smørbukk Nord Discovery is located in the Norwegian Sea.

The discovery is included in the Åsgard Field which is located in the central Norwegian Sea at water depths of between 240m and 300m.

Smørbukk Nord Discovery and Reserves

For planning and appraisal, the wildcat well 6506/9-3 was drilled on the Halten Terrace on the Smørbukk Nord in the Norwegian Sea.

The main objective of drilling was to find the presence of petroleum in the Middle-Early Jurassic Garn, Ile, and Tofte formations.

The other objectives of drilling were to prove petroleum in the Early Jurassic Tilje, Ror, and Åre formations and test the presence of hydrocarbon-bearing sands in the Early Cretaceous Intra-Lange Formation sandstones.

The well was drilled with Transocean Leader, a semi-submersible installation, in June 2013 to a total depth of 4,692m in the Early Jurassic Åre Formation. No shallow gas was found while drilling the well.

To a depth of 1,171m, the well was drilled with seawater and hi-vis and from 1,171m to 4,692m with XP-07 oily mud.

Between 3,723m and 3,885m, partially calcite-cemented sand stringers containing fair gas saturation were penetrated in the Lange Formation.

A 47m gas/condensate column was encountered in the Garn and Upper Not formations at 4,284m with a down-to-contact.

The reservoir characteristics in the Garn and Upper Not formations were found to be of good quality and poor quality in the Ile Formation.

At 4,305.7m, gas condensate was proved in the MDT sample of the Ile Formation and oil in the sample at 4,346m.

As per the geochemical analysis of the cores, a gas-oil contact was encountered at 4,346m and oil at 4,348m.

The Åre Formation was found wet with water and the deeper Tilje and Tofte formations contained gas in a tight reservoir.

The MDT fluid samples were taken at 4,250.9m (gas condensate), 4,305.7m (gas condensate), and 4,346m (oil and water). All were found to be highly contaminated with mud filtrate.

No stem drill test was performed on the well so, the well was permanently abandoned in August 2013 as a gas/condensate discovery.

A production well 65006/12-NC-1 was put to drilling in November 2023 with the semi-submersible installation Transocean Encourgae.

The drilling is being conducted to test the presence of gas/condensate in the well.

Smørbukk Nord Project Details

The development of the Smørbukk Nord Discovery will increase the lifetime and recovery from the Åsgard Field.

In October 2022, the Final Investment Decision (FID) of the Smørbukk Nord Discovery was finalised.

As a brownfield discovery, the discovery will be developed with a subsea tieback in the Åsgard Field on the continental shelf of Norway.

The infrastructure of the discovery will include a high-pressure and a high-temperature subsea production system and related facilities.

The Åsgard B gas and condensate platform is being modified for increased production from the Smørbukk reservoir.

The modifications include installation of systems for high- and low-pressure production, replacement of reinjection compressors, and other modifications.

For drilling in the block 6506/9, the Petroleum Safety Authority of Norway has given consent to Equinor to use Transocean Encourage in June 2023.

In February 2024, Equinor received the consent of the Norwegian Ocean Industry Authority (Havtil) to use the Smørbukk Nord Discovery and associated modifications on Åsgard B.

Contractors Involved

Equinor selected TechnipFMC for an Integrated Engineering, Procurement, Construction and Installation (iEPCI) contract for the Smørbukk Nord Discovery in January 2022.

The contract was followed by the Front-End Engineering and Design (FEED) contract of the project awarded in 2021.

The modifications contract of the Åsgard B gas and condensate platform was awarded by Equinor to Aker Solutions in March 2021.

The scope of the contract includes Engineering, Procurement, Construction, and Installation (EPCI) of new equipment for the platform.

The work on the contract has commenced and is scheduled to be completed in 2024.

For the work, around 415 man-years are expected with more than 1,600 jobs.

Transocean Leader is owned by Transocean Offshore Europe and Transocean Encourage by Transocean Services.

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The 500MW project is being developed by a consortium of EDF Renewables and Korean Western Power (KOWEPO). Wadi Noor Solar Power company, a special purpose vehicle owned by the consortium, will own, operate and maintain the 500MW solar PV plant.

The groundbreaking ceremony for the project was held in September 2023.

The consortium reached the financial close on the Manah-1 project in December 2023. It is expected to start commercial operations in the first quarter of 2025.

Once operational, Manah-1 is estimated to power over 50,000 Omani households with green renewable electricity and offset more than 700,000 metric tonnes of carbon dioxide per annum.

Manah-1 Power Plant Project Location

The Manah-1 solar PV IPP will be located in Oman’s Al Dakhiliyah Governorate, approximately 120km South of Muscat.

Overall, the site will encompass an area of around 775.33 hectares. Site elevation ranges between 340m and 350m above sea level.

Manah-1 and Manah Solar II are located adjacent to each other at a site in Manah.

Manah I Solar PV IPP Project development

The Manah-1 Solar PV IPP is designed as a greenfield solar PV plant with a maximum power export capacity of 500MWac. The output voltage from the Manah-1 power plant will be exported to the electrical transmission system via the 400 kV Manah switching grid station constructed by Oman Electricity Transmission Company (OETC) near the project site.

The solar project will utilise bifacial N-Type modules installed on 1P single-axis trackers to generate clean energy.

The PV modules will be connected in series to form PV strings, which are subsequently connected to the string inverters.

The generated Direct current (DC) power will be converted to Alternating Current (AC) power through string inverters connected to Low Voltage/ Medium Voltage (LV/MV) transformers that will feed the 33kV internal grid.

The 33 kV AC power will be transformed into 400 kV using two HV transformers 33 kV/400 kV in the Manah Solar I IPP substation and exported to the Manah OETC substation with maximum auxiliary consumption of 1000kVA (Kilo-volt-amperes) via two 400 kV underground cables.

The PV IPP project will include approximately 1,043,911 PV modules, each with a CV capacity of 600–605-watt peak (Wp) leading to a total DC nameplate capacity of 630MWp at Standard Test Conditions (STC).

Each PV string will include 31-32 units of PV modules and 18 – 19 PV strings per inverter give a total of 33,670 PV strings.

Other electrical components include 1740 units inverters with rated capacity of 295kVA (50 degrees Celsius) capable of handling the total DC capacity of the PV arrays in the arrangement and with an AC capacity of 513.3Mva, 60 units ITS (Integrated Transformer Station) rated at 8.8MVA 0.80/33kV, twenty 33kV PV feeder groups with three ITS for each are laid along solar farm buoy channel into 33kV switchgears.

Manah-1 Power Purchasing Agreement

In March 2023, the consortium entered into a 20-year Power Purchase Agreement (PPA), starting scheduled commercial operations date (SCOD) with Oman Water and Power Procurement Company SAOC (OPWP).

The consortium will be eligible to sell the green electricity under the spot market regime in Oman after the PPA expiry.

Financing

The stakeholders officially signed the financing agreements during COP28, leading to the financial close, achieved on the 25th of December 2023.

The project will be financed through equity and loan schemes from local and international financial institutions, including the Export-Import Bank of Korea, European Bank Société Générale and Oman Bank Muscat.

Contractor Involved

WNSPC selected Worley as the owner engineer for the Manah I Solar PV IPP.

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The Tyrving will be developed as a subsea tieback to the Alvheim FPSO.

The offshore field is owned by Aker BP (61%), Petoro (27%), and PGNIG Upstream Norway (12%).

The plan for development and operation (PDO) for Trell & Trine was submitted to the Ministry of Petroleum and Energy (MPE) in August 2022 and was approved in June 2023.

Total investments are estimated to be approximately NOK 6bn ($700m). Production from the Tyrving is expected to commence in the first quarter of 2025.

Location Details

Tyrving Develeopment project includes three wells Trell, Trine and Trell North.

Trell North, not included in the reserves estimates, will be explored via a drill hole from the Trell well.

The discoveries are located approximately 5km apart from each other and about 24km east of the Alvheim Floating Production Storage and Offloading Unit (FPSO).

Trell Discovery is located in block 25/5, production licence PL102F. Trine is located in block 25/4, production licence PL036E/F.

The water depth in the area is 119m and the reservoir is located between 2100 – 2200m True Vertical Depth referenced to Mean Sea Level (TVD MSL)

Discovery and Exploration Details

The Trine Discovery Well (25/4-2) was drilled in 1973.

The well discovered oil in Late Paleocene sandstone at a depth of 2133.5 m TVD MSL.

A nine-metre-thick oil column was found from the top of the reservoir down to an oil-water contact (OWC) at 2142.5m TVD MSL.

The Trell well (25/5-9) drilled in 2014, discovered a 21m oil column in the Heimdal Formation with an OWC at 2178 m TVD MSL.

The Tyrving reservoirs contain oil in sandstone of Paleocene age in the Heimdal Formation, at depth of 2140 and 2180m.

Reserves

Tyrving is estimated to contain recoverable resources of approximately 25 million barrels of oil equivalent (MMbbl).

The Tyrving field is estimated to produce very low emissions, approximately 0.3kg CO2 per barrel.

Tyrving Development Details

The Tyrving development is planned with three wells and two new subsea installations to be tied back to the existing infrastructure on East Kameleon Pipeline End Manifold (PLEM) and then to the Alvheim FPSO.

Tyrving reservoirs are planned to be drained using bilateral horizontal producers.

Each field comprises a 2-slot template, and they will be produced through a 15km pipeline to the East Kameleon PLEM.

The project will utilise pipeline capacity with the East Kameleon field connected to the Alvheim FPSO. Oil production from the project is expected to be supported by a water drive from the Heimdal aquifer.

The well stream will be transferred to the Alvheim FPSO by pipeline and offloaded to shuttle tankers.

The produced gas will be transported from Alvheim via a pipeline to the Scottish Area Gas Evacuation (SAGE) pipeline in the UK sector.

Alvheim FPSO Details

Alvheim field is located in the central part of the North Sea, approximately 10km west of Heimdal, near the UK sector border.

The Alvheim field includes multiple oil and gas deposits in addition to the original deposits Kneler, Kameleon, Boa and Vilje. Several other new discoveries are planned to be tied into the Alvheim FPSO.

The Alvheim commenced production on 8 June 2008, and it will be upgraded according to the requirements of the new subsea tie-ins from the Tyrving development.

Contractors Involved

Aker Solutions was engaged to provide the subsea production system for the Trell and Trine field in August 2022.

Under the contract, Aker Solutions will be responsible for delivering a subsea production system including three horizontal subsea trees, two manifolds, control systems, 30km subsea umbilicals and installation work.

Subsea 7 was awarded an engineering, procurement, construction and installation (EPCI) contract by Aker BP for the Trell and Trine development.

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With significant gold and silver credits, the project is regarded as one of the largest copper deposits in the globally.

The project is being developed by Oroco Resource.

A Preliminary Economic Assessment (PEA) of the copper project was filed by Oroco in October 2023. As per the PEA, the project has a total Life of Mine (LOM) of 23 years.

Santo Tomás Location and Site Access Details

The Santo Tomás Project is located in the Municipality of Choix situated at the northern border of the Sinaloa State and the southern border of the Chihuahua State.

The mineral resources are located in the Sinaloa State on the southern bank of the Rio Fuerte River in the Sierra Madre Occidental.

The project can be accessed by a 169km paved highway from the Topolobampo Port to the northern Choix Town via the Los Mochis City.

The project can also be accessed from the Chihuahua Pacific Highway via secondary unsurfaced roads, from El Ranchito by the current access road to a further 38km along unimproved roads via Cajón de Cancio, and via the El Sauzal Mine access road turning off at 38km.

Santo Tomás Ownership History

Since 1900s, informal miners have been working at the project site. Many small excavations and two small adits have been produced in the North and South Zones of the project.

ASARCO Mexicana S.A. conducted the first systematic exploration at the site in 1968 by constructing an access road from El Bienestar Ranch. The company drilled mostly in the North Zone.

The property was optioned by Tormex Mining Developers Ltd. (Contratista Tormex S.A.) and Industria Minera Peñoles in 1973. Both companies conducted exploration and re-sampling till 1977 on the North Zone.

The Mexican Government agencies included the project in a series of regional airborne surveys, LANDSAT imagery, helicopter surveys, and geological mapping in 1980s and 1990s.

By using the existing data, Esmeralda Group and Minera Real de Ángeles S.A. de C.V. produced mineral resource calculations, the results of which are not available.

The Esmeralda Group produced a new set of geological sections and plan maps after the resumption of exploration in 1990.

Minera Real de Ángeles and re-assayed two holes re-logged 12 ASARCO drill holes in 1991 resulting in a block model resource calculation. The results of this study are also not available.

The Esmeralda Group signed a purchase agreement of the property with Cerro de Cobre Inc., a Canadian company and optioned it to Exall Resources Ltd. in 1992.

Exall conducted a 4,000m drill program in 1993 which consisted of 33 reverse circulation drill holes and seven diamond drill holes. In 1997, Exall sold its option on the project.

Morgain Minerals Inc. and Minera MGM S.A. de C.V., a wholly owned subsidiary of Morgain, signed an agreement with Mr Rubén Rodríguez in 1997-98 to acquire 100% interest in the project.

The technical data regarding the bench-scale testing of copper concentrates was evaluated by Morgain with consultants resulting in a series of north-facing vertical sections at 1:1,000 scale but no further information regarding the agreement was found by the author.

Rubén Rodríguez transferred the 100% ownership of the project to Compañía Minera Ruero, S.A. de C.V., a Mexican private registered mining company, in 2002. Compañía Minera is owned by Ruero International Ltd. (99.998%) and Rodriguez (0.002%).

A USA company, Fierce investments Ltd. signed a share purchase agreement in 2002 with Rodriguez in to acquire the shares of Ruero International.

Several technical reviews of the project were successfully completed by Cambria Geological Ltd. (2005) and Cambria Geosciences Inc. (Cambria) (2006-2009).

A revised report of the mineral resource estimate was prepared by John Thornton in 2010.

The 100% ownership of Ruero International went back to Rodriguez through a decision of the Supreme Court of the Commonwealth of Bahamas in 2015.

Presently, Ruero International is owned by Altamura Copper (50%) and Rodriguez (50%).

Xochipala Gold, a subsidiary of Altamura, acquired 100% interest in the project from Compañía Minera Ruero in June 2016. The court judgement impeded the registration of the sale agreement and the transfer of title to Xochipala which was nullified in 2019.

Compañía Minera Ruero held seven core concessions until December 2019. In 2016, Compañía Minera Ruero and Xochipala signed a concession agreement by which Xochipala received 100% title of the seven concessions.

In October 2018, Oroco signed a definitive option agreement with Altamura. Oroco held an approximate 13% interest in Altamura at that time.

In March 2020, Oroco acquired Altamura receiving an outright control of the project.

Santo Tomás Geology and Mineralisation

The mineralisation of the project, porphyry copper-molybdenum-gold-silver, is closely linked to the Late Cretaceous to Palaeocene (90-40Ma) Laramide Orogeny.

The project and other porphyry copper deposits in Mexico are situated along a 150,000m (1,500km) long NNW trending belt extending from the southwestern USA to the Guerrero State of Mexico.

The evolution of this belt is related to the accretion of allochthonous terranes comprising a basement of Palaeozoic accreted sedimentary rocks and Triassic rift-related meta-igneous rocks.

The basement is overlain by Middle Jurassic and Early Cretaceous arc-related rocks of the Guerrero Arc.

The project area hosts Mesozoic country rocks consisting of marble, limestone, sandstone, andesitic volcanic rocks.

The dominant intrusive lithology is related to mineralisation and Late Cretaceous (~75Ma) quartz monzonite.

The mineralisation is dominantly controlled by the Laramide-age deformation, sulphide mineralisation, and hydrothermal breccias.

The sulphide mineralisation is dominated by pyrite, chalcopyrite, molybdenite, and minor bornite, chalcocite, and covellite. These are distributed in altered andesite country rock and quartz-monzonite.

The minor mineralisation is linked with replacement-style and skarn mineralisation in the hanging wall limestone with copper oxides occurring near the surface.

The alteration consists of wide zones of potassic, silica-albite, phyllic, propylic, and argillic hydrothermal alteration.

Mineral Resource Estimate

The total indicated mineral resource estimate of the Santo Tomás Project is 561Mt containing 4,579Mlb of copper equivalent (CuEq) at a grading of 0.37%, 4,077Mlb of copper at a grading of 0.330%, 98.4Mlb of molybdenum at a grading of 0.008%, 487.4Koz of gold at a grading of 0.027g/t, and 37,762Koz of silver at a grading of 2.1g/t.

The total inferred mineral resource estimate of the project is 549.1Mt containing 4,166Mlb of CuEq at a grading of 0.34%, 3,729Mlb of copper at a grading of 0.308%, 88.8Mlb of molybdenum at a grading of 0.007%, 375.8Koz of gold at a grading of 0.021g/t, and 34,458koz of silver at a grading of 2g/t.

Mining Methods and Processing of Ore

The proposed method to mine ore from the mine is open-pit truck and shovel method with 10m bench intervals.

A total of 847.7Mt of the mineralised material will be processed with an average grading of 0.36% of CuEq. The processing plant will have a throughput of 60 kilo tons per day (kt/d) in the first year of production followed by 120kt/d from second year.

A maximum material movement capacity of 107Mt per year will be required to support the processing plant.

A total of 983.6Mt of waste will be generated which needs to be removed resulting in a strip ratio of 1.16 over a 23-year life of mine including two years of pre-stripping.

Using hydraulic mining shovels (5-29m³) and front-end loader (1-22m³), the blasted material will be mined to mine waste and stockpile claim.

The material will be trucked using 194 tonne mining haul trucks to the processing plant for processing.

The processing plant is anticipated to produce 646t/d of copper concentrate at an average grading of 26.9% and 7.1t/d of molybdenum concentrate at an average grading of 45%.

The run-of-mine (ROM) will enter a three-stage primary crushing circuit reducing the size of ROM to a P₈₀ of 143mm from an F₁₀₀ of 1,200mm.

The size of ROM will be reduced further by the secondary crushing circuit from an F₈₀ of 143mm to a P₈₀ of 42mm. The tertiary HPGR crushing circuit will reduce the size further to a P₈₀ of 5.6mm.

The grinding circuit will reduce the particle size of the material to a P₈₀ of 150µm from an F₈₀ of 5,600µm.

The reduced material will enter a bulk rougher flotation to recover a mixture of copper and molybdenum concentrate.

The regrinding circuit will reduce the rougher concentrate particle size to a P₈₀ of 23µm from an F₈₀ of 125µm.

Copper and molybdenum will be floated in a bulk cleaner flotation circuit thereby increase in grades. The molybdenum rougher flotation tails will be copper concentrate.

The molybdenum grade will be increased to 45% in the molybdenum cleaner flotation circuit.

Both concentrates will be thickened to a solid density of 60% weight by weight by a hi-rate thickener.

The thickened concentrate will be filtered by a vertical pressure filter resulting in a final copper concentrate with 9% moisture.

The molybdenum concentrate will also be filtered resulting in a filtered molybdenum concentrate with 15% moisture which will be dried to 5% moisture and bagged.

To recover quality sand for dam construction, the flotation tailings will enter a thickener circuit which will advance to a sand cyclone system.

The cyclone O/F fines will be deposited in the tailing storage facility after thickening in a slime thickener.

The water recovered from the thickener will be sent to the sand plant process water tank.

As a pH modifier, quick lime will be added to the grinding circuit as a flotation promoter.

Aerophine 3418A will be used as a collector and methyl isobutyl carbinol as a frother. These will be added to the cleaner and bulk rougher flotation circuits.

In the molybdenum circuit, sodium hydrosulphide will be used as a depressant to depress copper.

To promote sedimentation of solids and dewatering, flocculant will be added to tailings thickener, concentrate thickeners, and slime thickener.

Project Infrastructure

The infrastructure required for phase 1 (60kt/d throughput) includes onsite and offsite facilities.

The onsite infrastructure consists of earthworks development, onsite roads, water management systems, site facilities, buildings, and electrical facilities.

The offsite infrastructure includes a site access road, a switch electrical substation, a power line, fresh water supply, pipes, a waste rock storage facility, and a tailing storage facility.

The infrastructure for phase 2 (120kt/d throughput) consists of onsite and offsite infrastructure.

The phase 2 onsite infrastructure includes a processing plant, additional facilities and buildings, earthworks development, water management systems, and site electrical power facilities.

The phase 2 offsite facilities include upgrades in switch electrical substation.

The proposed raw water option for the processing plant is groundwater at a maximum consumption rate of 2,244m³/h for both phases of the project (1,122m³/h for each phase).

The pipes used for the project will be over 1,500m (1.5km) of carbon steel pipe of 610mm diameter and a 2,300m (23km) of SDR 11 HDPE pipe with 762mm diameter.

Power Transmission

The power supply will be provided by an existing 230kVA high voltage power transmission line connecting the Huites Hydroelectric Plant.

The transmission line will be connected to the switch electrical substation and a new transmission line will also be connected to the switch electrical substation which will be routed to a new electrical main substation located at the site of the project.

The electrical substation and new power supply line will supply power for both phases of the project.

From the grid, the high voltage transmission line will connect a new switch electrical substation and a new power distribution line to a new electrical main substation of 230kV/34.5kV onsite.

For phase 2, the new electrical main substation will be expanded depending on the energy demand.

Contractors Involved

Ausenco Engineering USA South Inc. prepared the October 2023 PEA of the Santo Tomás Project

SRK Consulting US Inc. and SRK Consulting Canada (collectively SRK) completed the mineral resource estimate and data verification work of the project.

SRK (Vancouver) conducted work related to deposit type, mapping, exploration, and geological setting of the PEA.

Mining Plus Consulting Ltd. was selected to develop a mine plan based on the mineral resource estimate developed by SRK of the PEA.

A helicopter magnetics survey of the project site was completed by Terraquest Ltd. in March 2021. The independent quality monitoring of the survey was provided by Condor Consulting, Inc. of Lakewood, CO.

In June 2021, the three-dimensional induced polarisation (DCIP) geophysical survey was conducted by Dias Geophysical of Saskatoon, Saskatchewan. Dias conducted a similar survey in November 2020.

A technical report of the project was prepared by Dane A. Bridge Consulting Inc. of Calgary, Alberta in June 2019.

Bateman prepared an update to the 1994 PFS of the project in 2003.

In 2002, IGNA Engineering and Consulting Ltd. was selected to conduct the geological study and evaluation of the project.

The technical data of the project was consulted by Morgain with Cominco Engineering Services Ltd. in 1997-1998.

The Pre-feasibility Study of the project was prepared by Bateman Engineering Inc. of Phoenix, Arizona in 1993.

In 1992, the available exploration data of the project was reviewed by Watts, Griffis a d mcQuat.

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SSE Thermal and Equinor announced plans to develop the project in 2021.

An Environmental Impact Assessment (EIA) Scoping Report of the project was published in March 2023. In the same year, a scoping report was submitted to the East Riding of Yorkshire Council.

In August 2023, the Aldbrough Hydrogen Project was selected by the UK Government for the final stage of Net Zero Hydrogen Fund, which supports the development and deployment of new low-carbon hydrogen production.

Subject to planning consent, construction works are expected to begin in 2024 and take around 36 months. The project may begin production in 2028.

Once complete, the hydrogen storage facility will have an initial capacity of at least 320 gigawatt hours (GWh). This is enough to power more than 860 hydrogen buses annually.

The project will also support in decarbonising the carbon-intensive Humber region and help UK to achieve net zero by 2050.

Aldbrough Hydrogen Pathfinder Location

The Aldbrough Hydrogen Pathfinder Project is proposed to be built within the brownfield site of the Aldbrough Gas Storage Facility in East Yorkshire.

The Aldbrough Gas Storage Facility, co-owned by SSE Thermal and Equinor, commenced commercial operations in June 2011. The final cavern (ninth) of the facility started production in November 2012.

From the Aldbrough Gas Storage Facility, a below-ground brine discharge pipe runs east to the North Sea. This area is included in the scoping boundary.

A temporary construction area has been identified to the north of the pipe and coast.  A second construction area will be 100m south of the site.

The site can be accessed via the B1242 Aldbrough Road.

Aldbrough Hydrogen Pathfinder Infrastructure

The Aldbrough Hydrogen Pathfinder Project is expected to involve the development of a green hydrogen production, storage and energy generation facility by converting one of the site’s existing natural gas storage caverns.

The electrolysers, a water treatment plant, a demineralised water storage facility, a hydrogen buffer vessel, a low-pressure compression facility, and an electrical compound will be housed in the western plot.

The eastern plot will house the cooling system, a dehydration and letdown plant, a higher-pressure compression plant, and an Open Cycle Glass Turbine (OCGT).

The marine infrastructure of the project will include the existing High-Density Polyethylene (HDPE) pipe that needs to be re-lined and re-burial of the existing HDPE pipe.

The re-lining of the existing HDPE pipe is expected to consist of excavation of the pipe on the beach near the clifftop compound by using a mobile excavator (conventional excavation method). The excavation is expected to be conducted on approximately 750m² area.

The excavated material will be used to refill the pit after re-lining is completed. The pipe will be cut, the cut end will be retrieved and will be followed by the re-lining of the existing pipe with a smaller diameter pipe.

The smaller diameter pipe will be pushed through the existing pipe to the end of it around 600m from the shore. After re-lining, the HDPE pipe will be reburied to a suitable depth.

Operational Details

The Aldbrough Hydrogen Pathfinder Project will integrate a salt cavern storage facility (20-gigawatt hour (GWh)), an electrolytic hydrogen production facility (35 megawatts of electrons (Mwe)), and a low carbon hydrogen power production through OCGT of up to 50Mwe net capacity.

The project will deliver up to 4,000 kilograms per hour (kg/h) of hydrogen from the caverns.

The Proton Exchange Membrane Electrolyser will produce hydrogen via electrolysis. The project will receive renewable power from the grid under Renewable Power Purchase Agreements (RPPAs) complying with the Low Carbon Hydrogen Standard.

The electrolyser will utilise demineralised water and will be supplied from the existing licenced Aldbrough borehole water supply.

Aldbrough’s existing natural gas storage caverns (Aldbrough 1) will be converted into a salt cavern storage facility. The cavern is filled with natural gas so it will be rewatered and then filled with hydrogen displacing the water/brine.

The cavern will produce and store hydrogen which will be distributed through an above-ground pipeline connecting the OCGT.

The OCGT will operate on up to 100% hydrogen and export power back to the grid during low renewable power availability.

The electrolysis will also produce oxygen which will be transferred to the atmosphere. The use of oxygen from the project in hospitals and other applications will be accessed.

Contractors Involved

The EIA Scoping Report of the project was prepared by Environmental Resources Management (ERM).

Siemens Energy and Black & Veatch were selected by SSE Thermal to deliver the Front-End Engineering and Design (FEED) of the project. Siemens Energy and Black & Veatch are already delivering FEED.

SSE Thermal has joined hands with Siemens Energy for the delivery of the first phase of the project.

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The company announced a Preliminary Economic Assessment (PEA) of the HMN Li project in 2019. The PEA estimated a 30-year mine life based on a production of 5,000 tonnes per annum (tpa) of lithium carbonate.

The Environmental Baseline Study (EBS) for the project was completed in March 2022. It was filed with the Mining Authority in May 2022.

In November 2023, Lithium South filed an Updated Mineral Resource Estimate which increased the lithium resource base in the project by 175%.

The company is advancing with a full feasibility study for the HMN Li Project.

Hombre Muerto North Project Location

The HMN Project is located in Salta Province, northwestern Argentina, around 380km from the city of Salta. It straddles the Salta and Catamarca Provinces in the southeastern Puna region.

Overall, the 5,687-hectare property comprises nine mining concessions, including six on the salar.

The six concessions are Alba Sabrina, Tramo, Natalia Maria, Gaston Enrique, Via Monte and Norma Edith.

The three additional properties, known as the Sophia properties, are located approximately 6km north of the Salar del Hombre Muerto (SHM) in Salta Province. The processing facility is anticipated to be constructed at the Sophia properties.

Notably, Korean company Pohang Iron and Steel Company (POSCO) is building a $4bn lithium project adjacent to Lithium South, while Allkem Livent with their new merger will develop the west and east portions of the salar.

Background Details of Hombre Muerto North Project

NRG Metals entered into an option agreement to purchase the HMN Li project in June 2017. Subsequent exploration work by the company was reported in the technical reports by Montgomery (2017; 2018) and KPC (2019).

In May 2019, NRG Metals formed a strategic alliance with US-based lithium extraction company Lilac Solutions to develop pilot project work for the HMN Li project.

Lilac had developed an ion exchange technology, called the IX Process, to address the challenges of conventional evaporative extraction of lithium from brines. According to Lilac, the process achieved 90% recovery of lithium from brine, which is double compared to evaporative technology.

In May 2021, Lithium South announced working with Eon Minerals, a Florida-based technology company, to evaluate the use of Direct Lithium Extraction (DLE) technology for its HMN Li project.

In October 2023, the first production well at the lithium brine project was installed.

In January 2024, Lithium South signed an agreement with POSCO Argentina to collaborate on the development of the HMN Li project.

Geology and Mineralisation

Salar del Hombre Muerto (SHM) is situated in the southern zone of the central Andean Puna-Altiplano plateau and features low-lying internally drained basins (salars).

The Alba Sabrina property includes a trending channel in the northwestern sector of the SHM, while the Natalia Maria property represents a halite-dominated area of the SHM.

Tramo is located in SHM’s clastic-dominated northeastern sector of the SHM.

Alba Sabrina, Natalia Maria, and Tramo properties’ brine resources are defined relative to a 500 mg/L lithium cut-off.

According to a project technical report published in 2023, the lithium grades and the levels of impurities in the project are regarded favourably against other brine deposits.

Hombre Muerto North Project Resources

In September 2023, Lithium South reported a 175% increase in the total lithium brine resources at HMN Li Project.

The resource base increased from 571,000 tonnes to 1.58 million tonnes (Mt) LCE at an average grade of 736 mg/L lithium with a low average magnesium (a brine contaminant) to lithium ratio of 3.27.

This includes in situ contained resources at the Alba Sabrina, Natalia Maria, and Tramo claim blocks.

Around 90% of resource is in the measured category.

Mining and Recovery

At Hombre Muerto North, well holes equipped with internal pumps will transfer brine to one of three pre-concentration ponds situated near the processing plant.

The PEA noted that nearly 100 L/s of brine will be required to feed the ponds and processing plant and produce 5,000 t/a of lithium carbonate (Li₂CO₃). It estimated that three well holes will enable it to achieve the rate, while additional holes will be drilled as a contingency measure.

The brine is a high-grade, low impurity brine – 736 milligrams lithium per litre. It contains a low magnesium to lithium ratio of 3.27 to one.

The recovery method involves lithium salar concentration and pre-purification through solar evaporation. This will be followed by advanced hydrometallurgical processing to purify the brine and recover Li₂CO₃.

The brine produced from the wells will be pre-concentrated through solar evaporation in shallow ponds. It will be followed by liming to remove bulk-impurities.

Subsequent chemical adjustment, solvent extraction and polishing precipitation will remove boron and advanced impurities.

Li₂CO₃ will be precipitated by carbonation with sodium carbonate and then purified by re-dissolution with carbon dioxide and re-precipitation by desorption.

Finally, the lithium carbonate will be dried, conditioned and packaged.

Key Infrastructure

A 600MW, 375kV power line connecting Salta and Mejillones in Chile passes about 160km north of the HMN Li property. A new line must be constructed to power the mining operations.

A natural gas pipeline also passes around 10km from the property area.

Freshwater required for the process plant operations will be provided by wells located approximately 3km away.

Offtake Agreement

In November 2017, Lithium South entered into a lithium off-take agreement with Chengdu Chemphys Chemical Industry. The off-take agreement gave Chengdu exclusive right of first offer (ROFO) to buy a portion or all lithium production from the HMN Li project.

Contractors Involved

Lithium South engaged Groundwater Insight to prepare an independent technical report for the lithium brine project.

Knight Piésold and JDS Energy & Mining prepared the Preliminary Economic Assessment Report for the Hombre Muerto North project.

The Environmental Baseline Study was completed by E&C Consultores.

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The KKLP pipeline will connect the Hunter Power Project (HPP), a 750MW gas-fired peaking power station being developed by Snowy Hydro in Kurri Kurri to the existing Sydney to Newcastle Pipeline (SNP) (formally Jemena Gas Networks).

The storage pipeline would provide up to 70 Terajoules (TJ) of gas storage to supply the HPP at maximum power output for up to 10 hours.

Australian-based leading energy infrastructure business, APA Transmission, a wholly owned subsidiary of APA Group, is the owner and operator of the pipeline.

KKLP project received approval from the NSW Government under the Environmental Planning and Assessment Act 1979 in December 2022.

The total estimated capex costs of approximately A$450m ($289.3m).

APA was granted a pipeline licence under the Pipelines Act 1967 in September 2023 and the pipeline construction is planned to commence in October 2023.

The KKLP is expected to have an operational life of 30 years.

Kurri Kurri Lateral Pipeline Details

The project area is situated in the Lower Hunter region of New South Wales, encompassing the Local Government Areas (LGAs) of Cessnock, Maitland and Newcastle.

The KKLP transmission pipeline will commence near Black Hill, approximately 15km northwest of Newcastle and connect to the Hunter Power Project, approximately 2km north of Kurri Kurri.

APA executed a 30-year Gas Transportation and Storage Agreement and a Development Agreement with Snowy Hydro, to commence the development of the Kurri Kurri Lateral transmission and storage pipeline to the HPP in June 2022. Snowy Hydro may extend the agreement for a further 10 years.

The KKLP received federal approval from the Department of Climate Change, Energy, and the Environment and Water under the Environment Protection and Biodiversity Conservation Act 1999 (EPBC Act) in April 2023.

The KKLP received the Pipeline Licence approval from the NSW Office of Energy and Climate Change under the Pipelines Act 1967 in October 2023.

The KKLP has been declared Critical State Significant Infrastructure (CSSI) under Section 5.13 of the NSW Environmental Planning and Assessment Act 1979.

Kurri Kurri Lateral Pipeline Pipeline Components

The KKLP project comprises one 21km transmission pipeline, a 24km high-pressure storage pipeline and a compressor station, delivery station, and other ancillary surface facilities.

A buried, 21km transmission with medium diameter (approximately 14-inch), and medium pressure (up to 6.9-megapascal) will deliver gas supply from the existing SNP to the HPP. The Transmission line will be fully buried with a typical depth of cover of 900mm.

The project development includes a compressor station at the end of the transmission pipeline to boost gas pressure to the required inlet pressure of the HPP.

A 24km buried steel storage pipeline with a 42-inch diameter and high-pressure storage (up to 15.3-megapascal) will be developed to hold up to 70 TJ of gas to supply the HPP at the required inlet pressure.

The JGN delivery facility is proposed to be developed near the connection of the KKLP transmission pipeline and the existing SNP pipeline.

A delivery station will be installed with equipment to control the temperature, pressure and flow rate of gas before delivery of gas from the storage pipeline to the HPP.

Jemena, the operator of the SNP pipeline will be responsible for the design, planning approvals, construction and operation of the JGN delivery facility including a 600 m short section of pipeline between the JGN delivery facility and the SNP.

The KKLP project is designed to allow gas flow back to the SNP from the storage pipeline.

Contractors Involved

Spiecapag, which specialises in constructing pipelines and associated facilities, was engaged to construct the lateral and storage pipelines for the KKLP.

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Formerly known as Non-Conventional Energy Development Corporation of Andhra Pradesh Limited (NEDCAP), M/s New & Renewable Energy Development Corporation of Andhra Pradesh (NREDCAP) will be the nodal agency behind the project development.

With an estimated total project cost of INR24.06bn ($290m), the project will have peak operating duration of 5.58 hours and will be commissioned approximately four years from the start of the project as planned. For pre-construction activities, additional nine months have been planned.

A new EIA notification was issued in September 2006 by the Ministry of Environment Forest and Climate Change (MoEF&CC) of the Government of India. According to this notification, the project is a Pumped Storage Hydroelectric Project (PSHEP).

In October 2021, the MoEF&CC issued the Terms of Reference (TOR) for the project. Based on TOR, the EIA study was completed successfully.

An Environmental Impact Assessment (EIA) and Environmental Management Plan (EMP) Report of the project was published for NREDCAP in March 2023.

The MoEF&CC granted environmental clearance to NREDCAP in August 2023.

Location Details of Chitravathi Pumped Storage Project

The Chitravathi Pumped Storage Project is proposed on the Chitravathi River, a tributary of the Pennar River and will be located at the border of YSR Kadapa and Sri Satya Sai districts of Andhra Pradesh.

The project site is accessible from the State Highway SH 121. The nearest airport to the site is Tirupati Airport (260km), the nearest railhead with unloading facilities is Chinnekunta Palli (30km), and the nearest port is Krishnapatnam Port (280km).

Approximately 136 hectares (ha) will be the total land required for construction activities.

The Chitravathi dam is located in the YSR Kadapa District and the reservoir in the Sri Satya Sai District.

The Chitravathi Balancing Reservoir (Sri Penchikala basi Reddy) is located across the Chitravathi River near Parnapalli Village, Lingala Mandal, YSR Kadapa District.

The new upper reservoir and components will be constructed on the left bank of the Chitravathi Dam near Peddakotla Village, Sri Satya Sai District.

Chitravathi Pumped Storage Project Components

The embankment dam of the project will be a clay core rockfill type dam made up of excavated material from the reservoir, water conductor system, and underground caverns. The dam will have a 10m wide crest, an upstream slope of 1V:2.25H, and a downstream slope of 1V:1.75H.

The upper reservoir will be newly constructed with available live storage of 0.216 Thousand Million Cubic Feet (TMC) (6.11 Million Cubic Metre (MCM)), and Elevation Level (EL.) 495m at Full Reservoir Level (FRL). The existing lower reservoir has EL. 298m FRL and live storage of 10.1TMC (1.22MCM).

There will be a diffuser-type upper intake structure of 6 bays with 5.9 widths each. It will have a sill intake level of EL. 442.50m. The intake structures will have trash racks to prohibit entry of the floating debris into the system.

There will be two generating units of the water conductor system which will receive water from a single power intake structure. A steel-lined 7.7m diameter main penstock will be divided near the powerhouse and transport water to the independent generating units at a horizontal angle of 60^o.

The water conductor system will consist of one number steel lined pressure tunnel divided into two-unit penstock. These units will feed 2 number of vertical shaft reversible Francis turbines of 250MW each. They will be housed in an underground powerhouse cavern (105*24*50.25m) (length*breadth*height) located on the left bank of the lower reservoir. The operating floor and crown of the powerhouse will be at El. 263.60m and El. 285m respectively.

A 35m long service bay (unloading cum erection bay) will be located at the operating floor level of El. 263m on the east side of the powerhouse and a 90*18.5*31.10m (length*breadth*height) transformer cavern will be situated 36m downstream of the powerhouse cavern.

The isolated phase bus will directly connect each generating unit of the powerhouse to three single-phase generator step-up transformers.

The transformer cavern will house seven single-phase transformers, including a spare transformer, at an El. 263m. At El. 275m, a gas-insulated switchgear will lie on the floor above the transformers.

Two tail race tunnels are proposed for the project: one 200m long circular concrete-lined tail race tunnel with a 10.7m diameter and second 5.5m diameter circular tailrace tunnels emerging from the draft tube end.

The tailwater from the powerhouse will enter back into the river via the tail race tunnel in the turbine mode of the operation. In the pumping mode, the tail race tunnel will convey water to the reversible turbine from the lower intake structure.

A lower intake structure of diffuser type will be built on the left bank of the Chitravathi River. The structure will help in the smooth entry of water from the lower to the upper reservoir.

Chitravathi Pumped Storage Project Working Details

The Chitravathi Pumped Storage Project will consist of two reservoirs. The Chitravathi balancing reservoir will act as the lower reservoir and a new reservoir will be built on the hilltop with an embankment of 57.3m maximum height.

The new reservoir will be created for cyclic use for the storage and discharge of energy.

If there are evaporation losses then, these will be recouped periodically.

The project entails the re-utilisation and non-consumptive use of 0.216TMC of water for re-circulation amongst both reservoirs.

Chitravathi Pumped Storage Project Contractors

In March 2023, the EIA and EMP Report for the project was prepared and published by Architects Engineers and Consultants (Aarvee Associates).

Aarvee Associates also successfully completed the feasibility study and detailed project report for the project in July 2021.

Commenced in November 2020, the Pre-feasibility study (PFS) and Detailed Project Report (DPR) were successfully completed by Energy Infratech.

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Wintershall Dea operates PL836S Bergknapp with 40% interest. Equinor (30%) and DNO Norge (30%) are the other two partners. The licence was awarded in Awards in Predefined Areas (APA) 2015 by the Norwegian authorities.

Equinor became a stakeholder in the licence after it bought Spirit Energy Norway’s key assets in 2022.

The operator discovered oil in Bergknapp prospect in 2020. This was followed by a gas discovery in the deeper Åre Formation in 2021.

In December 2023, the partners completed the drilling of an appraisal well at the discovery and began assessing potential field development alternatives.

Bergknapp Discovery Location

The Bergknapp Discovery in PL836S is located 8km west of the Maria Field and 200km north of the Kristiansund on the west coast of Norway.

The water depth in the area is around 312m below sea level.

Bergknapp Discovery and Appraisal Details

In April 2020, the 6406/3-10 well, the first in PL836S, discovered oil at Bergknapp prospect. The well found oil in the Middle (Garn Formation) and Lower Jurassic (Tilje Formation) reservoir rocks.

In the primary target, the well encountered hydrocarbon-bearing sandstones of about 35m in the Ile Formation and an oil column of 120m in the Tilje Formation.

The 6406/3-10 well also encountered about 60m of oil column in Garn Formation.

The well was drilled to a total vertical depth of 4,566m below sea level and was terminated in the Åre Formation.

It was partially drilled by the West Mira drilling facility, and then completed by the Scarabeo 8 drilling facility.

In 2021, the 6406/3-10 A well was drilled as a geological side-track to well 6406/3-10 to appraise the oil discovery in the Garn, Ile and Tilje formations. Besides hitting oil columns in the three formations, the well encountered a gas column of approximately 260m in the Åre Formation.

In December 2023, an appraisal well 6406/3-12 S confirmed the Bergknapp Discovery. Drilled using Transocean Norge platform, the well encountered a 59m oil column in the Ile Formation, about 146m column in the Tilje Formation and a 108m oil column in the upper part of the Åre Formation.

It was drilled to a vertical depth of 4729m below sea level and terminated in the Åre Formation from the Early Jurassic.

Reserves

Wintershall Dea updated resource estimates for the Bergknapp discovery following the completion of appraisal drilling in December 2023.

The asset is expected to contain between 44 million and 75 million barrels of oil equivalent in the Garn, Ile and Tilje formations.

The resource estimate for the Åre Formation ranges between 6 and 25 million barrels of oil equivalent.

Bergknapp Discovery Development

Bergknapp and Åre Formation are assessed as potential subsea developments.

The partners are expected to consider tying the discovery into existing infrastructure in the region, as it is located near several other producing fields.

Wintershall Dea operates Maria and Dvalin field in the area around Bergknapp.

Key Contractors Involved

Transocean Norge rig was used for drilling the appraisal well for the Bergknapp Discovery.

Notably, Wintershall and OMV Norge contracted Transocean for the use of Transocean Norge for 17 wells in September 2022.

Under the contract, the Transocean Norge rig was supposed to be used to drill 11 operated wells for Wintershall Dea and six operated wells for OMV. The rig may also be used to drill additional potential wells until 2027.

The 6406/3-10 A well was drilled by Odfjell Drilling’s Deepsea Aberdeen rig.

Seadrill’s West Mira drilling rig and SAIPEM’s Scarabeo 8 drilling facility were also used for drilling activity.

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