Table 9 – Reservoir Fluid Composition (Aurora-1 MDT Sample, T-090)** Jumper required to connect the existing Cluster 1 manifold to the new FLET. * Flowline 3 will reuse spare 11.5” flexible pipe from prior project inventory.Table 12 – Unconstrained Case, Flowing Wellhead Pressure (FWHP)This document establishes the preliminary Basis of Design for the offshore production facilities and associated subsea systems forming part of PROJECT ALPINE, located within the Horizon South offshore exploration block in the Pelagia Basin. The scope addresses both topside and subsea infrastructure intended to support the commercial development of the field, including provisions for integration with the Central Nexus Facility.The content herein consolidates the current understanding of the Aurora-1 and Epsilon-4 wells, encompassing reservoir performance characteristics, produced fluid properties, and indicative well productivity profiles. It also incorporates the latest available geomorphological surveys and metocean design parameters relevant to installation and operational considerations in the northeastern seaboard waters of Valmora Island.An initial conceptual arrangement of the field development system is provided, outlining potential subsea architecture, tie-back routes, and processing options. This arrangement is intended as a baseline reference for PRIME ENERGY and its project partners—Stratos Energy Ltd. (Operator, 40% interest), Novara Petrochem (30%), and Helix GeoVentures (30%)—to support further engineering definition by prequalified tenderers.The document will be progressively refined as PROJECT ALPINE advances through its development phases. Updates are anticipated at key decision gates, including prior to Front-End Engineering Design (FEED) commencement, and following the incorporation of new data from drilling campaigns undertaken by TerraNova Drilling Co. and other service providers.The hydrocarbon resource under consideration is situated within the Horizon South offshore exploration block, part of the greater Pelagia Basin along the northeastern maritime boundary of Valmora Island. Horizon South is currently under the operatorship of Stratos Energy Ltd. (40% participating interest), in partnership with Novara Petrochem (30%) and Helix GeoVentures (30%). The concession was secured under a revised production-sharing arrangement tailored to distribute investment risk among stakeholders, with contractual rights awarded in August 2019 and commercial terms becoming effective in January 2020.The first exploratory campaign in the block was executed through the drilling of the Aurora- 1 well, undertaken by TerraNova Drilling Co. The well was spudded on 21 May 2002 inwater depths of approximately 2,436 feet, reaching a total measured depth of 13,441 feet (true vertical depth of 13,100 feet). Drilling operations concluded on 7 June 2002.Historical exploration in the vicinity had already indicated hydrocarbon potential, most notably through the Epsilon-4 well drilled in 2001 by former license holder BlueArc Resources. Both Aurora-1 and Epsilon-4 are positioned along the southwestern flank of the principal structural high, separated by a subsurface saddle feature that influences reservoir connectivity and development planning.The preferred development concept foresees a subsea tie-back to existing offshore facilities, leveraging underutilized processing and export infrastructure approaching late- life production. This approach provides a cost-efficient route to commercialization while mitigating the environmental footprint of new installations. The planned connection point is strategically located in proximity to the Central Nexus Facility, thereby reducing the extent of modifications required and facilitating smooth integration into the established production network.Refer to [7]. Any project activities within PROJECT ALPINE that could potentially affect the surrounding environment—such as pre-commissioning or hydrotesting of subsea flowlines—shall undergo a detailed assessment in coordination with the project’s HSE (Health, Safety & Environment) team. This ensures that any relevant environmental thresholds, as established under Serandia’s legislative framework, are identified and adhered to prior to execution.All applicable acts, laws, rules, and regulations for PROJECT ALPINE shall align with those enforced for offshore operations within Serandia. In cases where multiple regulatory frameworks overlap, the most stringent requirement will take precedence.1. Serandian national laws, regulations, and any international conventions ratified by Serandia pertaining to offshore exploration and production.2. Applicable classification society requirements, vessel flag regulations, marine international standards, and certification body rules for the specific equipment category.4. PRIME ENERGY corporate engineering standards (latest revision to be applied to new equipment per [3] [Reference origin not found]).5. Internationally recognized codes and standards relevant to the scope of work.The Aurora-1 gas discovery well was drilled in 2,436 ft water depth by TerraNova Drilling Co. under contract with a prior project operator, reaching total depth on 7 June 2002 at a true vertical depth subsea (TVDSS) of 13,100 ft. Following a series of unsuccessful development proposals for Aurora-1 and nearby discoveries, the acreage was relinquished.In 2019, the Serandian Ministry of Energy reoffered the block during its offshore licensing round, where Stratos Energy Ltd. (Operator, 40%), Novara Petrochem (30%), and Helix GeoVentures (30%) secured exploration and exploitation rights under the revised production-sharing framework.The proposed development of Aurora-1 provides a synergistic opportunity to extend the operational lifespan of the Horizon South asset. Declining output from nearby producing fields offers capacity in the existing infrastructure, enabling the new project to deliver incremental reserves and economic benefits to both the Government of Serandia and the project stakeholders along the gas processing and export value chain—from the subsea wellhead to the onshore terminals.The selected concept is a subsea tie-back to the Central Nexus Facility, leveraging ullage in late-life infrastructure and proximity to existing manifold clusters. The base plan comprises two new production wells tied into Horizon South Trunkline 1 via a new subsea production flowline. Production from Cluster 1 will be redirected for processing through Cluster 3, optimizing field performance while minimizing additional topside modifications.Environmental parameters for the Pelagia Basin, including seawater temperature profiles, current regimes, and wave statistics, are provided in Ref. [25]. These datasets form the baseline for offshore design criteria in compliance with Serandian regulatory requirements.The Horizon South development area spans water depths between approximately 300 m and 1,200 m below mean sea level.The primary floating production unit (FPU) within the Central Nexus Facility is located at the following reference coordinates:The coordinates for the onshore receiving and processing facilities (ORF) associated with Horizon South are as follows:5.1.4 Environmental Reference Data For detailed metocean parameters—including design return periods—refer to Ref. [25]:Design return periods applicable to offshore oil and gas facilities are governed by national regulations or industry codes. For guidance specific to PRIME ENERGY projects, refer to Company Standard 28842.ENG.OFF.STD “Meteo-Oceanographic Design Basis”.• 36” Conductor – depth 906 m MDNo dedicated geotechnical investigation has yet been performed for the Aurora-1 development area. A comprehensive site survey is planned in upcoming project phases to characterize seabed soils at proposed subsea structure, flowline, and umbilical installation locations.Geophysical survey data are not currently available for the Aurora-1 project footprint. A future campaign will acquire high-resolution bathymetry and shallow sub-seabed profiles to support engineering and hazard assessments. This will include seabed morphology mapping, shallow stratigraphy, and identification of potential hazards to subsea infrastructure.Current bathymetric information is limited to low-resolution (12.5 m × 12.5 m grid) data obtained from reprocessed 3D seismic datasets. The development area is characterized by complex seabed topography, including multiple submarine canyons (both primary and tributary), distinct fault lines, steep escarpments, irregular slopes, and isolated mounded features. Water depths range from approximately 300 m to 1,500 m.Figure 3 – Regional morphology of the Pelagia Basin development zone.Figure 4 – Detailed bathymorphic interpretation of the Aurora-1 sector from reprocessed 3D seismic volume.No dedicated geohazard studies have been carried out to date for the Aurora-1 development area. This assessment will form part of the upcoming geophysical and geotechnical survey scope.Seismic design criteria for subsea structures and associated foundations shall be in accordance with ISO 19901-2.The primary reservoir identified within the Aurora-1 structure of PROJECT ALPINE is classified as T-090 (equivalent to legacy interval 3130 from the former operator’s nomenclature). This unit was encountered at depths between –2,400 m and –2,600 m true vertical depth subsea (TVDSS).Secondary accumulations include T-088 / T-086 (equivalent to legacy 3140 and 3150) and T-084 Segment-1 (equivalent to legacy 3170). The field is a Pliocene-age turbidite system, deposited approximately 3.5 million years ago as toe-of-slope fans prograding across an anticlinal structure associated with the broader Pelagia Basin Hub anticline. Hydrocarbontrapping is predominantly stratigraphic, driven by the up-dip pinch-out of turbiditic sequences into a slope valley.The T-090 interval represents the principal gas-bearing horizon, accounting for roughly 74% of the estimated gas-in-place. Seismic amplitude and envelope attribute analyses illustrate a channel-fed fan geometry sourced from the northwest. Depositional lobes display compensational stacking with evidence of lateral amalgamation, which complicates architectural interpretation. No gas–water contact (GWC) was directly observed in well control; however, amplitude cut-off suggests a contact near –2,560 m subsea level.The T-088 / T-086 reservoirs were encountered approximately 30–40 m below the primary target, comprising two distinct sand bodies identified in the Aurora-1 and Epsilon-4 wells. MDT pressure testing confirmed a consistent gas–water gradient across both wells, with GWC observed at –2,556 m in Aurora-1, while Epsilon-4 proved water-bearing. These intervals are interpreted as more channelized deposits, with two primary fairways trending NW–S and NW–SE. Localized bottom-current reworking and crevasse splays are inferred in the southeastern portion of the block.The basal T-084 reservoir constitutes the lowest sand package of the Pliocene slope-valley system. Seismic RMS amplitude extractions indicate possible channelized features near Aurora-1 and depositional lobe development to the south of Epsilon-4. Gas saturation was confirmed in Aurora-1, with GWC measured at –2,626 m TVDSS by MDT, while Epsilon-4 did not penetrate this horizon. MDT data also indicate T-084 is moderately overpressured relative to overlying sands.Petrophysical evaluation from the 2020 Integrated Reservoir Study confirmed net pay and reservoir quality in both Aurora-1 and Epsilon-4 wells across T-090, T-088 / T-086, and T- 084 intervals. The results are summarized below.A 3D static model has been constructed, integrating seismic, well, and analogue data to better capture reservoir architecture and original gas-in-place estimates.No PVT experiments have yet been conducted on recovered cores from PROJECT ALPINE. Fluid characterization was therefore derived from MDT sampling at T-090, with analysis performed at 2,487 m depth, 3,903 psia reservoir pressure, and 151 °F reservoir temperature. Results indicate a methane-rich gas (C1 content 98.3%), with a gas gravity of 0.58 and condensate–gas ratio (CGR) of 5.8 stb/MMscf. The dataset was calibrated through an equation-of-state model (PVTi), and the T-090 fluid properties are currently applied to secondary reservoirs for preliminary design.The Aurora-2 well, drilled in May 2021, further confirmed reservoir quality in the T-090 interval. Full core and PVT analysis remain pending at the time of this Basis of Design.6.2 Reservoir Fluid Composition The molar composition of the produced fluid from Aurora-1 (T-090) is summarized below:The field development concept foresees the drilling of two production wells, provisionally designated as Well A-3 and Well A-4.The following tables summarize the preliminary wellhead coordinates as defined under current geodetic references (UTM / WGS 1984).• Datum: WGS 1984, UTM Zone 50S Well A-4 Parameter ValueAs no dedicated pore pressure study has yet been finalized, the casing program is based on analogues from previous deepwater projects in the same basin. The proposed casing/liner string dimensions and metallurgy are aligned with industry practice and prior successful campaigns.• 10-3/4” Liner – TOL 2051 m MD, length 1127 m, overlap 120 m Proposed Casing Setting Depths – Well A-4• 10-3/4” Liner – TOL 2152 m MD, length 1150 m, overlap 120 mCorrosion Considerations Formation fluid sampling indicates the presence of significant CO₂ partial pressure, requiring corrosion-resistant alloys for flow-wetted tubulars. The recommended material is13Cr (or Super 13Cr) stainless steel for production liner and tubing. For casing above the packer, carbon or low-alloy steel qualified for sour service in accordance with API 5CT is considered suitable.The well-completed strategy has been developed in line with international standards and internal well design procedures, incorporating the following principles:• Resilience against worst-case operating conditions Completion Concepts Under Evaluation1. Well A-3: Dual-zone completion within 10-3/4” liner, using Controlled Hydraulic Flow Profile (CHFP) and smart upper completion.2. Well A-4: Single-zone CHFP inside 10-3/4” liner, with provision for future dual-zone configuration if required. Smart completion capability will be retained for operational flexibility.The strategy emphasizes larger completion sizes to maximize gas deliverability compared with conventional 9-5/8” liner systems. Alternative designs may be considered in later project phases.A dedicated completion material and elastomer compatibility study has not yet been undertaken. Based on analogues from prior basin developments, 13Cr (or enhanced grades thereof) is anticipated to be the baseline metallurgy for cost and corrosion considerations. This selection will be revisited during subsequent project phases once reservoir fluid characterization is further refined.Given the combination of high pressure and relatively low temperature expected during both steady-state and transient operations, the reservoir fluids are predicted to be susceptible to hydrate formation.Hydrate risks will be mitigated under all scenarios through continuous injection of lean MEG solution (80% wt). A supplementary injection of methanol will be applied during start- up and restart operations to counteract low-temperature excursions and hydrate risks.No issues are anticipated with asphaltenes, foaming, or emulsion stability. However, scale formation potential is assumed to be present, consistent with analogue reservoirs in the basin.8.2 Reservoir Fluid Composition Reservoir fluid composition is referenced in Section 7.2. 8.3 Scale PotentialScaling tendencies are considered comparable to neighbouring developments within the basin. Preventive strategies will be aligned with established operating practices for carbonate-rich produced water systems.No wax deposition, foaming, or emulsion challenges are expected under reservoir or production conditions (see Section 9.1).Hydrate equilibrium curves were generated for reservoir fluid composition (Section 7.2), saturated at reservoir conditions of 30 bar and 74°C.Figure 5: Hydrate formation curves (to be inserted). 8.6 Hydrogen Sulphide The reservoir fluid is expected to be free of H₂S. 8.7 Asphaltenes No asphaltenes are expected in the produced hydrocarbons. 8.8 Material SelectionProduced fluids exhibit CO₂ partial pressure sufficient to cause sweet corrosion in the absence of H₂S. Dissolution of CO₂ into condensed water is expected, with concentrations proportional to partial pressure and temperature.The material and corrosion-control philosophy emphasizes maintaining integrity across the design life while minimizing cost and fabrication delays. Mitigation methods include:Uninhibited corrosion rate: estimated 0.9 mm/yr → ~8.8 mm wall loss over 20 years With inhibition: reduced to 0.1 mm/yr (based on analogous fluid classification studies)• Corrosion allowance (15 years, 95% CI inhibitor availability): 4.35 mm• Corrosion allowance (15 years, 95% CI inhibitor availability): 4.95 mmFlowline material basis: Carbon steel + 5 mm corrosion allowance, assuming >95% inhibitor availability.8.9 Flow Assurance Flow assurance considerations are detailed in Section 9.1.The forecasted flowing wellhead pressures (FWHP) for the development wells are presented in Table 12.Forecasted flowing wellhead temperatures upstream and downstream of the pressure control valves are summarized in Tables 13 and 14.For the base case, wells are produced in hybrid HP/LP mode, with arrival fluid temperatures expected between -2°C and +10°C depending on flowrate.Base Case: two new development wells are tied back via a 12” subsea production line into the existing trunkline system, routed through an intermediate cluster before reaching the central production hub.Representative production cases for host facility inlet conditions are summarized in Table 15. These cases are used to confirm processing and slug catcher capacity.• 616 MMSCFD max flow in LP mode (per production profile)• With debottlenecking, 720 MMSCFD can be managed in LP mode (up to ~8,400 m³/h seawater consumption)Produced gas and condensate will be processed at the host facility. Applicable sales specifications are:8.11.2 Produced Water Produced water will be treated onboard the host facility. Key discharge specifications:• Max HC content: 15 ppmv (30-day avg), 42 ppmv (daily peak)Discharge streams will be continuously monitored per applicable national and environmental regulations.8.11.3 H₂S Content Reservoir fluids are expected to be free of H₂S. 8.11.4 CO₂ Content Reservoir CO₂ content is ~0.92 mol%. 8.12 Field Flowrates for Design Basis Table 19 summarizes the design case flowrates used for facility capacity verification.The following section provides an overview of the subsea architecture for PROJECT ALPINE, covering subsea production hardware, umbilicals, subsea control systems, and flexible flowline arrangements.9.1.1 Floating Production Unit (FPU) For the overall process description of the Floating Production Unit, refer to [22]. 9.1.2 Design Life The subsea production and control system shall be designed for a service life of 20 years. 9.1.3 Maximum Water Depth All subsea equipment shall be rated for an installation water depth of 1,200 m. 9.1.4 Main Subsea EquipmentA preliminary list of key subsea components and associated design parameters is provided below.Table 20 – Preliminary List of Main Subsea Equipment1. Xmas Tree conditions in line with ALPINE field specification.2. MEG pump design pressure: 340 barg (PSV set point). Including hydrostatic head at 1,200 m = ~470 barg. See [32] for pressure definition under MEG packing conditions.3. Subsea structure pressure defined by wellhead shut-in pressure (WHSP) × 1.1 = ~270 bar.4. Design temperature includes operating maximum (55 °C) plus contingency margin (+15 °C).5. A new FLET is anticipated for connecting ALPINE Cluster 1 with Cluster 3 through a new interconnecting line.A dedicated electro-hydraulic umbilical system will be deployed to provide hydraulic power, chemicals, electrical supply, and control signals to the subsea production equipment [12].• The existing Cluster 1 Main Umbilical (UMB1) will be extended to support ALPINE subsea facilities.• UMB1: Flying leads will connect UTA-A to the Cluster 1 SDU and to the HIPPS. UTA-B will connect to Well ALPINE-3B and to UMB2 UTA-A.• UMB2: Configured in daisy-chain from UMB1. UTA-B will connect to Well ALPINE-4 via flying leads.Where practical, existing spare umbilicals from previous developments will be utilized to optimize design and reduce customization. For ALPINE UMB2, the spare infield UM1C from the LOCATION asset will be repurposed.Each Xmas Tree and HIPPS unit will be operated by a dedicated Subsea Control Module (SCM). Flying leads will distribute power and control between UTAs and host subsea structures.• The subsea control system shall be fully compatible with the existing ALPINE host system.• Design shall comply with COMPANY standard ENG.STA.STD.18010, with HIPPS designed to standard ENG.STA.STD.28746.• Hydraulic system design: closed-loop with return to the host facility.Topside integration will be through the existing ALPINE control system. Hardware modifications (one channel at a time) may be performed without shutting down Cluster 1. Software updates, however, could require temporary production shutdown. See [30] and [31] for integration details.Flexible pipelines have been selected for the ALPINE development. The table below summarizes preliminary design inputs for the flexible pipeline system and associated routing analysis.Flexible solutions were confirmed during concept selection for suitability under mechanical, operational, and environmental conditions at 1,200 m water depth. Rigid alternatives were evaluated but flexible lines were selected due to advantages in cost, schedule, and install ability.The Project shall be developed in alignment with applicable national regulations and corporate HSE requirements, taking into account international standards such as:• ISO 45001 (Occupational Health and Safety Management Systems)Corporate HSE policies and internal standards are used as the basis for defining the project HSE requirements. Preliminary HSE Philosophy has been prepared for the Concept Definition Phase, with the aim of ensuring an inherently safe design that:• Provides adequate escape and rescue provisions in emergencies.• Includes sufficient protective systems and redundancy to detect, isolate, and control accidental releases of flammable or toxic substances.• Ensures effective fire detection, control, and extinguishing systems.HSE development will be supported by a formal risk-based assessment process (e.g. HAZID, HAZOP, ESHIA, and other safety studies). The goal is to identify hazards, evaluate risks, and implement effective mitigation and control measures.• Provide redundancy and safety devices to contain uncontrolled releases.• Implement fire protection systems capable of controlling foreseeable fire scenarios.• Limit environmental pollution from accidental releases (spills, flaring, venting).• Reduce construction-phase risks, including work in brownfield areas.The overall design approach shall aim to eliminate intolerable risks and reduce tolerable risks to a level that is demonstrably ALARP (As Low As Reasonably Practicable), through:The Project shall comply with all health and regulatory requirements, ensuring that the health of employees and contractors is protected during design, construction, commissioning, and operations.• Identification and evaluation of occupational and community health risks (e.g., exposure, infectious disease, accommodations, water, food, vector-borne illness, medical support).• Regular inspections and monitoring, including industrial hygiene programs.4. Safe design for hazardous material storage and handling.SIMOPS refers to conducting multiple activities concurrently (e.g., hydrocarbon production alongside drilling, construction, commissioning, or maintenance).While SIMOPS allow production continuity and reduce downtime, they introduce additional operational complexity and risk, including:• Higher probability of hazards due to concurrent activities.• Increased ignition risks from hot work (e.g., welding, cutting) in areas near hydrocarbon systems.Effective planning and control are required to manage SIMOPS risks while maintaining production.10.4 Risk Identification During the current Project Phase, the following structured studies will be performed:• HAZID (Hazard Identification): Systematic early-stage review of potential external threats with the potential to create health, safety, environmental, asset, or reputational risks.• HAZOP (Hazard and Operability): Detailed review of design and operations for new or modified process/utility systems, ensuring compliance with safety and operational standards.The purpose of these assessments is to identify risks early and define mitigation actions.All recommendations raised during the studies shall be tracked, assigned, and closed prior to completion of the Project Phase.An ESHIA has been developed during the FEED phase. The results of the study will be provided to the Contractor for incorporation into detailed design.The Project is committed to reducing greenhouse gas (GHG) emissions throughout all phases of development and operation. Emission reduction will be achieved through the adoption of appropriate technologies, optimization of energy consumption, and application of best industry practices across the asset lifecycle.During installation and commissioning, the following activities may be conducted concurrently, introducing additional complexity and risk:Water management is a core element of environmental protection. The following design and operational requirements apply:The Project’s operational strategy aims to ensure continuous and reliable production while prioritizing safety, cost efficiency, and environmental protection. Key objectives include:Compliance will be ensured through management systems aligned with international standards, industry best practices, and applicable national regulations. Asset lifecycle processes will be governed under the Development Management System (DMS) and the Operations Management System (OMS).• Leverage support infrastructure to optimize staffing levels.• Ensure high levels of competence across operational teams.• Adopt empowerment approaches for efficient work execution.• Utilize contracting plans to supplement workforce with specialized expertise.• Align workforce planning with local content requirements.This section outlines requirements for Simultaneous Operations (SIMOPS) and Concurrent Operations (CONOPS) in relation to new project developments near existing or operating facilities.Risk assessments shall be carried out to evaluate interactions between simultaneous activities and define mitigation measures.For the Floating Production Unit (FPU), it is assumed that certain activities under the Engineering, Procurement, Construction, and Installation (EPCI) scope may occur concurrently with production operations. Further studies will determine:• Alternative strategies if concurrent execution is deemed unsuitable.Table 1 – Central Nexus Facility FPU CoordinatesTable 6 – Average Reservoir Properties from Aurora-1 and Epsilon-4 WellsTable 7 – Average Reservoir Properties from Volumetric ModelingNote: This qualitative risk ranking is subject to project-specific calibration.Note: This qualitative risk ranking is subject to project-specific calibration.