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And we have Haida Hazri… Her input/support must be valuable…

Thailand?

1. Chevron’s Remaining Thai Assets

* Production: Small offshore fields, possibly around 3,000 boe/d.

* Reason: Chevron is reducing its footprint in Thailand, and these fields could be available for sale or farm-down.

2. MedcoEnergi’s Bualuang Field

* Production: Approximately 3,000 boe/d.

* Reason: The field’s concession expires in 2025, and MedcoEnergi may look to exit or divest.

3. Mubadala Energy’s 40% in Erawan PSC

* Production: Large, but uncertain volume.

* Reason: Mubadala may consider exiting over time, but the timing and details are unclear.

Could something like this be of interest to SEA?

Here’s a short list of **producing gas fields** in Malaysia (and nearby) where **Seascape Energy** could potentially farm into a **small non-operating working interest** (\~3,000 boe/day target):

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### **1. PM3 CAA PSC (Malaysia–Vietnam)**

* Operator: Hibiscus Petroleum (35%)

* Status: Producing gas and condensate

* Net Production: \~7,300 boe/day

* Why it fits: Producing, scalable, structured for non-op WI participation.

### **2. MLJ Field (Brunei, Block B)**

* Operator: Brunei Shell (Hibiscus acquiring 37.5% WI)

* Status: Producing gas-condensate

* Net Production: \~7,900 boe/day

* Why it fits: Producing gas, non-op model, just outside Malaysia.

### **3. PTTEP Gas Fields (Sarawak Offshore)**

* Operator: PTTEP

* Status: Producing \~160 mmscfd gas (26,000+ boe/day)

* Why it fits: Large fields, but small WI carve-outs may be available.

### **4. JDA Block A-18 (Malaysia–Thailand Joint Development Area)**

* Operator: CPOC (Petronas/PTTEP JV)

* Status: Mature producing gas asset (400+ mmscfd)

* Why it fits: Structured for multi-party participation; possible small WI entry.

Hopefully some production coming our way. As for new blocks, they have plenty to apply for. But these won’t be awarded until end year and early next.

Thailand end date for application was July 16th ish. But no time frame for when awards will be announced.

Malaysia August, December and April 2026.

Still think GM has a big role to play soon.

Note, don’t post when a little tipsy. No substance in my last post 😳😂🙈

Hi all, just away on hols in France, not long now to some more changing news.

You can expect Seascape Energy Asia’s CPR to be released sometime between late August and the end of September.

If they’re aiming to coincide with investor newsflow (like capital raises or development announcements), the CPR might be timed toward:

Late August – to catch post-summer market attention.

Mid-to-late September – before Q3 earnings blackout periods begin.

In short: late August to mid-September is the most probable window, unless delayed.

If Rockhopper is successful in moving the Sea Lion oil field toward development — meaning they secure final investment decision (FID), financing, and government approval — the effect on the share price would likely be substantial. The company’s current market capitalization is around £460 million (about $600 million), but its net asset value (NPV10) from Sea Lion alone is independently estimated at around $1.85 billion. That means the market is currently only pricing in about a third of the project’s value. If Sea Lion progresses as planned, Rockhopper’s share price could realistically double or triple over time, depending on oil prices and execution by the operator (Navitas). The key point here is that this is a large, partially de-risked project. The upside is significant, but it would likely unfold in stages — as each milestone is achieved (such as securing funding, sanctioning the project, or starting construction), the stock would re-rate upward.

In contrast, Seascape Energy Asia has a much smaller market cap — around £29 million (approximately $35 million) — and a very different asset mix focused on gas. If Seascape successfully moves its Temaris cluster (42 million barrels of oil equivalent, fully owned) into approved development, it could unlock net value of over $150–300 million. Given the current low valuation, even modest recognition of this asset in the market could cause the share price to double or triple. That could happen relatively quickly if offtake agreements or development approvals are announced.

More dramatically, if Seascape's Kertang exploration well, scheduled for 2025, results in a significant gas discovery, the upside could be explosive. Kertang contains over 1.7 billion barrels of oil equivalent (gross, unrisked), and Seascape has a 10% carried interest — meaning it won’t pay for the drilling but will benefit fully from success. If the well hits, Seascape’s net interest would represent 150 million barrels or more, potentially worth hundreds of millions of dollars. In that case, the share price could increase by five to ten times or more — this is the kind of binary, high-impact event that transforms microcaps into midcaps almost overnight. However, the geological chance of success is estimated at around 20%, so there is meaningful risk.

In summary, Rockhopper offers a larger-scale, lower-risk oil development story with potential for steady upside as the project advances. Seascape is more speculative, but has far more dramatic short-term upside if one of its assets — especially Kertang — succeeds. Investors looking for steady rerating might prefer Rockhopper; those seeking asymmetric, high-risk/high-reward outcomes may lean toward Seascape.

With a pinch of salt(Maybe more than a pinch)

Rockhopper – Sea Lion Oil Field (Falkland Islands)

Rockhopper holds a 35% working interest in the Sea Lion field, with Navitas as operator. Based on an independent assessment (June 2025), Rockhopper’s net 2C contingent resources are approximately 255 million barrels of oil.

The estimated net present value (NPV) at a 10% discount rate (NPV10), assuming Brent crude at around $70 per barrel, is about $1.85 billion for Rockhopper’s share. This figure is post-Falkland Islands Government royalties and taxes. Gross 2C resources are around 917 million barrels, meaning Rockhopper’s stake is substantial.

The breakeven price is estimated at $25–30 per barrel, with strong economics over the life of the project. First oil could potentially be achieved near 2030, depending on final investment decision (FID) timing and project financing.

________________________________________

Seascape Energy Asia – Kertang, DEWA, Temaris Fields (Malaysia)

Seascape is developing three distinct gas assets in Malaysia, each with different profiles:

1. Temaris Cluster (including Tembakau and Mengkuang):

100% owned by Seascape.

Gross recoverable gas resources are around 42 million barrels of oil equivalent (mmboe).

The asset is shallow-water, close to infrastructure, and part of a Malaysian fast-track development program (SFA).

Applying a $5–10 per barrel valuation range, the gross value is roughly $210–420 million, with Seascape retaining full value after PSC terms. Net NPV to Seascape is estimated at $165–330 million.

2. DEWA Complex:

Seascape owns around 28%.

Gross gas-in-place is roughly 500 billion cubic feet (around 83 mmboe).

Expected recoverable volume net to Seascape is in the 14–18 mmboe range.

Targeting first gas in 2027 with full field development plan (FDP) expected by end of 2025.

3. Kertang Prospect (Block 2A):

Massive exploration upside: gross unrisked mean prospective resources are over 9 trillion cubic feet of gas plus 146 million barrels of NGLs, totaling around 1.7 billion boe.

Seascape retains a 10% carried interest after farm-out to INPEX, equating to a net unrisked position of about 166 mmboe.

However, this is high-risk exploration with an estimated 20% geological chance of success. Drilling is scheduled for 2025.

________________________________________

Comparison Summary

Rockhopper’s Sea Lion is a large, appraised oil field with a clear path to development and a multi-billion-dollar valuation. It is lower-risk in terms of subsurface uncertainty but depends on external financing and political stability in the Falklands.

Seascape’s assets are gas-focused and located in Malaysia, a more established upstream environment. Temaris and DEWA offer lower-risk, near-term production potential, while Kertang represents a high-impact but high-risk exploration target. Seascape’s current market valuation does not fully reflect the upside potential, particularly if Kertan

Transocean Skyros

* Contract ends: September 2025 (West Africa)

* Availability: Early to mid-2026

* Suitable for drilling in late 2025 or early 2026

* Proven ability to relocate globally

Transocean Deepwater Invictus

* Contract ends: Mid-2026 (Gulf of Mexico)

* Availability: Mid to late 2026

* Suitable for drilling from mid-2026 onward

Transocean Deepwater Proteus

* Similar profile to Invictus

* Contract ends: Mid-2026

* Availability: Mid to late 2026

Transocean Deepwater Conqueror

* Same class as Invictus and Proteus

* Availability: Mid to late 2026

Summary

* For drilling in late 2025 to early 2026:
→ Skyros is the best-aligned rig

* For drilling in mid to late 2026:
→ Invictus, Proteus, or Conqueror are strong candidates

Deepwater Nautilus (Transocean)

* Ultra-deepwater semi-submersible

* Water depth capacity: ~2,400 meters

* Drilling depth capacity: ~9,000 meters

* Currently under contract with Petronas

* Contract expected to end before or during 2026

* May become available if not renewed

Maersk Viking (Drillship)

* 7th-generation ultra-deepwater drillship

* Water depth capacity: ~3,600 meters

* Drilling depth capacity: ~12,000 meters

* Operating for Shell and PTTEP through early to mid-2025

* May be available in 2026 if options are not exercised

Dorado / Zonda / Draco (Eldorado Drilling)

* Samsung 12K ultra-deepwater drillships

* Water depth capacity: ~3,600 meters

* Drilling depth capacity: ~12,000 meters

* Arrived in Malaysia in 2024

* No confirmed long-term contracts

* Likely open or available in 2026

These rigs are all technically suitable for Kertang and are either already in the region or newly mobilized to Southeast Asia.

No, just have a bit of spare time to dig around the net.

The team have been out to Petronas Geoscience Centre today, looking at rock core from Temabakau -2, 140m worth.

Sure! Here's a clean version of the presentation details for **Seascape Energy Asia** that you can copy and use:

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Event:** SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition (APOGCE) 2025 Location:** Jakarta, Indonesia

Date:** October 14–16, 2025

Presenter:** Matthew Choo, Head of Exploration, Seascape Energy Asia

Session:** Poster Session 8 – *New Play Concept & Deepwater Exploration*

Presentation Title:** *"Unlocking Sarawak’s Deepwater Frontier – the Unexplored Giant in Block 2A, North Luconia"*

How Much Upside?

In the Malay Basin, gas fields often experience reserve growth of 20% to 50% post-discovery, especially after appraisal drilling or improved subsurface understanding. For the Temaris field, which currently holds 42 million barrels of oil equivalent (mmboe), potential upside could be:

Low-case upside: ~8 mmboe increase (total ~50 mmboe)

Moderate-case upside: ~15 mmboe increase (total ~57 mmboe)

High-case upside: ~21 mmboe increase (total ~63 mmboe)

This upside could result from appraisal success, reservoir extensions, or reclassification of contingent resources to reserves.

Examples of Reserve Upside in Malay Basin Fields

1. Seligi Gas (PM8E PSC)

In 2024, EnQuest and partners announced additional 155 Bscf (~27 mmboe) of gas brought into the Seligi development.

This represented a significant reserve uplift, achieved through better reservoir understanding and tie-back planning.

Reserve growth was approximately 25–30% compared to initial volumes.

2. Bunga Orkid Field (PM3 CAA)

After early production, reservoir performance and new appraisal wells showed better connectivity and reservoir quality.

Recoverable reserves were revised upward by 20–35% over time.

The field benefited from well placement optimization and pressure support from adjacent structures.

3. Tapis Field (PM-3 Block)

Originally developed as an oil field, Tapis later yielded additional gas volumes during redevelopment phases.

Gas cap expansion and recovery factor improvements led to significant upward revisions — again in the 20–50% range.

4. D35/D21/J4 Cluster (Sarawak Basin, but structurally similar)

Although just outside the Malay Basin, this mature cluster saw reserve upgrades of 30–40% after Petronas Carigali and Roc Oil invested in infill drilling and 4D seismic.

The learnings are applicable due to similar carbonate and clastic depositional settings.

Reserve growth of 20–50% is realistic and supported by nearby Malay Basin examples such as Seligi, Bunga Orkid, and Tapis

Kecubung

Reservoir: Mainly Miocene sandstones with moderate porosity (18–22%) and permeability (50–150 mD).

Pay thickness: Approximately 20–30 meters net pay.

Drilling: Discovered by the Kecubung-1 well drilled in the late 2000s during a PETRONAS-led exploration program. Limited appraisal wells followed.

Reservoir fluids: Light oil with API gravity around 35–40°.

Status: No commercial development to date due to marginal size and infrastructure challenges.

Ledang Barat

Reservoir: Miocene deltaic sandstones, porosity averaging 16–20%, permeability ranging 30–100 mD.

Net pay thickness: Approximately 15–25 meters.

Drilling: Discovered by Ledang Barat-1 well in early 2010s; limited appraisal done, no development wells drilled.

Fluid type: Medium-light oil, API 32–36°.

Challenges: Remoteness and moderate reservoir quality limited prior development interest.

Belanga

Reservoir: Miocene deep marine sandstones, moderate porosity (~17–21%), permeability around 40–120 mD.

Net pay: Estimated 10–20 meters.

Drilling: Belanga-1 drilled mid-2010s as a wildcat; no follow-up wells.

Fluid: Light oil, API 38°.

Status: Undeveloped due to small size and marginal economics.

Ophir

Reservoir: Miocene turbiditic sandstones with good reservoir quality. Porosity around 18–24%, permeability 100–300 mD.

Pay thickness: Net pay about 40 meters across multiple zones.

Drilling: Ophir-1 discovery well in 2012; multiple appraisal wells drilled before production start.

Development: Production started in 2017, using subsea wells tied back to FPSO. Several infill wells drilled to sustain output.

Fluid: Medium crude oil, API ~34°.

Field produced ~20–25 MMbbl before partner exit and decline phase.

Bekok

Reservoir: Multi-layered Oligocene–Miocene sandstones, porosity 20–28%, permeability 150–400 mD.

Net pay thickness: Up to 80 meters in some sections.

Wells: Multiple development wells drilled since the 1970s; detailed appraisal and infill drilling ongoing.

Fluid: Light oil with some associated gas.

Production: Large cumulative volumes produced over decades; still active under ExxonMobil operation.

Seligi

Reservoir: Similar to Bekok, stacked Miocene sandstones with good porosity (22–27%) and high permeability (200–500 mD).

Pay thickness: Net pay typically 50–70 meters.

Wells: Numerous appraisal and development wells since the 1970s.

Fluid: Light oil with some gas cap.

Production: Still producing actively; field infrastructure integrated with Bekok.

Kepong

Reservoir: Miocene sandstones, porosity 18–23%, permeability 100–200 mD.

Net pay: Approximately 30 meters.

Wells: Development wells drilled since early 1970s, integrated with Bekok-Seligi infrastructure.

Fluid: Medium oil, API 33°.

Production: Moderate output; still under PSC.

Tinggi

Reservoir: Miocene sandstones, porosity 17–22%, permeability 80–180 mD.

Net pay: About 25–35 meters.

Wells: Several development wells drilled historically.

Part 2

Kecubung

Discovered in the 2000s–2010s by PETRONAS or one of its PSC partners.

Remains undeveloped; likely deemed sub-commercial under previous fiscal terms.

Estimated recoverable reserves are small, likely in the range of 10 to 30 million barrels of oil equivalent (MMboe).

Now part of the PM-509 Cluster in MBR 2025, offered under Enhanced Profitability Terms (EPT PSC) to improve economic viability.

Ledang Barat

Also discovered in the 2000s–2010s during PETRONAS-led exploration campaigns.

Not developed to date, possibly due to reservoir quality or infrastructure limitations.

Estimated recoverable resources likely in the small field category, between 15 and 35 MMboe.

Reoffered as part of PM-509 Cluster to encourage new capital and redevelopment strategies.

Belanga

Another small to mid-size discovery in the same structural trend as Ledang and Kecubung.

Remains undeveloped; considered marginal under legacy terms.

Estimated to hold approximately 10–25 MMboe recoverable.

Now reoffered as part of the same PM-509 Cluster under improved fiscal terms.

Ophir

Discovered in the early 2010s; development began following the award of a Small Field Risk Service Contract (RSC) in 2014.

Joint venture included Octanex (50%), Scomi (30%), and Vestigo (20%, a PETRONAS subsidiary).

First oil was achieved in October 2017.

Cumulative production over its initial production phase is estimated at approximately 20–25 million barrels.

JV partners exited the project before RSC expiry; PETRONAS took over operations and field was shut-in or declined significantly by 2023–2024.

Field is now being reoffered under MBR 2025 with potential for redevelopment, infill drilling, or rework of shut-in wells.

Bekok

A major historical discovery, found between 1969 and 1975 by Esso Malaysia in partnership with PETRONAS.

One of Malaysia’s legacy offshore giants, with estimated recoverable reserves in the range of 500 to 700 MMboe.

Produced oil and gas from stacked Oligocene-Miocene sandstones at moderate depths.

Still in production under an extended PSC operated by ExxonMobil Malaysia with PETRONAS Carigali as a joint venture partner.

Not included in current bid round; still under active contract.

Seligi

Another major discovery from the 1970s by the Esso-PETRONAS joint venture.

Combined recoverable resources exceed 500 MMboe.

Produced through large, faulted anticlinal structures.

Still operated by ExxonMobil Malaysia under a PSC, producing oil and associated gas.

Also not part of MBR 2025 offering; remains under long-term PSC.

Kepong

Medium-sized field discovered in the early 1970s.

Recoverable volumes estimated between 100 and 200 MMboe.

Produced from similar geological units as Bekok and Seligi.

Likely still producing under existing PSC terms through ExxonMobil Malaysia–PETRONAS JV.

Tinggi

Discovered during the same period as Kepong.

Moderate reserve base; historical estimates suggest around 120 MMboe.

Production and developm

From what I could originally see, the bidding round only showed 5 fields within the block. The other 4 one mentioned may not be part of PM 509…

Block PM‑509 is being offered in Malaysia Bid Round (MBR) 2025 despite containing previously discovered and even developed fields like Kecubung, Ledang Barat, Ophir, and Belanga. In total, Block PM‑509 covers approximately 4,000 square kilometers and contains nine known fields, including earlier discoveries such as Bekok and Seligi.

Fields in this block appear in MBR 2025 for the following reasons:

Contract expiry or relinquishment

Fields like Ophir were developed under Risk Service Contracts (RSCs) or Production Sharing Contracts (PSCs) with fixed durations. Once these contracts expire or the contractor relinquishes the asset, PETRONAS regains control and can re-offer the block to new investors. Some of these assets are now without active operators, or were never fully developed.

Repackaging into clusters

PETRONAS groups discovered fields with nearby leads or marginal accumulations and offers them as a single “cluster” under new terms. This increases commercial viability by enabling economies of scale, especially for fields that are too small to develop individually.

New fiscal terms

MBR 2025 introduces Enhanced Profitability Terms (EPT PSC) and Small Field Asset (SFA PSC) frameworks. These offer better profit splits, higher cost recovery caps, and simplified regulatory processes. Fields previously uneconomic under old terms are now reoffered with these improved incentives.

Uncommercial or marginal discoveries

Some fields in PM‑509 were discovered years ago but never brought to production due to poor economics, lack of infrastructure, or technological limitations. With new fiscal terms and bundling strategies, PETRONAS is making these fields viable again for development or redevelopment.

Specific field example:

Ophir was awarded under a Small Field Risk Service Contract in 2014 to a joint venture between Octanex (50%), Scomi (30%), and Vestigo (PETRONAS) (20%). Production began in 2017. Over time, partners exited the project, and PETRONAS took over full responsibility. The RSC term likely expired around 2024, making the asset eligible for re-offering in MBR 2025.

Fields in PM‑509 now included in MBR 2025 likely include:

Kecubung

Ledang Barat

Ophir

Belanga

Bekok

Seligi

Kepong

Tinggi

VIETNAM OFFSHORE BID ROUND 2025 – PARTICIPATION BRIEF

Bidding Timeline (Hanoi time, GMT+7):

Expression of Interest (EOI) and Data Room access opens: April 15, 2025 at 09:00

EOI and Data Room access closes: May 30, 2025 at 16:00

Bid document issuance opens: June 2, 2025 at 09:00

Bid document issuance closes: June 20, 2025 at 12:00

Final bid submission deadline: August 1, 2025 at 16:00 (sharp)

Expected results announcement: Between late September and mid-November 2025 (subject to PetroVietnam and government review timelines)

OIL DISCOVERY WELL DATA (Near Block 17 – Cuu Long Basin)

Hai Su Vang-1X

Location: Block 15-2/17 (adjacent to Block 17)

Operator: Murphy Cuu Long Tay Oil Co. Ltd.

Partners: PVEP (35%), SK Earthon (25%)

Drilled: Q4 2024

Water Depth: ~149 feet

Total Depth: ~13,124 feet

Net Oil Pay: ~370 feet (two stacked reservoirs)

Flow Rate: ~10,000 barrels/day (facility-limited)

Oil Gravity: 37° API

Gas-Oil Ratio: ~1,100 scf/bbl

Estimated Resources: 170–430 million barrels of oil equivalent (MMboe)

Lac Da Hong-1X

Location: Block 15-1/05 (adjacent to Block 17)

Operator: Murphy Cuu Long Bac Oil Co. Ltd.

Partners: PVEP (35%), SK Earthon (25%)

Drilled: Q1 2025

Water Depth: ~151 feet

Total Depth: ~13,616 feet

Net Oil Pay: ~106 feet

Flow Rate: ~2,500 barrels/day

Oil Gravity: 38° API

These wells demonstrate strong oil potential and are direct geological analogs for Block 17 in the current bidding round.

🗺 VIETNAM BID ROUND 2025 – BLOCKS AND HYDROCARBON TYPE

Block 17

Basin: Cuu Long Basin

Hydrocarbon Type: Oil-prone

Geological Context: Shallow water, high discovery rate, adjacent to producing oil fields

Best suited for: Fast-track oil development, lower exploration risk

Block 10/11

Basin: Nam Con Son Basin

Hydrocarbon Type: Mixed, but gas-leaning

Geological Context: Moderate-depth block, proximity to gas fields and pipeline corridor

Block 10&11-1

Basin: Nam Con Son Basin

Hydrocarbon Type: Primarily gas

Geological Context: Near large gas-condensate accumulations; access to Nam Con Son pipeline and infrastructure

Summary

For oil-focused bidding: Block 17 is the clearest target, with nearby high-quality discoveries (Hai Su Vang-1X and Lac Da Hong-1X).

For gas development: Blocks 10/11 and 10&11-1 offer long-term gas potential and pipeline access.

Thailand too? Bidding closes today.

Seascape Energy mentioned Thailand in its recent corporate presentation and earnings update as part of its strategic focus in Southeast Asia. During the full-year 2024 earnings call, Executive Chairman James Menzies identified Malaysia, Thailand, and Vietnam as the company’s top priorities for future growth. Additionally, in its February 2025 corporate outlook, Seascape Energy highlighted upcoming licensing rounds in both Malaysia and Thailand, indicating active interest in expanding its operations in the region.