RH Petrogas Confirms Dual Oil-Gas Discovery at Papua Well

A gas flow of approximately 4.2 million ft3/day plus 192 b/d of condensate emerged from the upper interval of the Upper Kais Formation at RH Petrogas’ Northwest Klagagi-1 well, giving the company the gas-condensate result it drilled for. A second, lower interval then produced oil, an outcome that was not part of the original well objective.

That combination, a new oil-and-gas discovery at a single well in a mature Indonesian block, matters more for a mid-cap independent than the raw numbers suggest. RH Petrogas (SGX: T13) operates through its roughly 82.65%-owned subsidiary Petrogas (Basin) Ltd, which holds a 70% working interest in the Kepala Burung production sharing contract (PSC) in Southwest Papua. That block has produced more than 360 million barrels of oil and 270 billion ft3 of gas over its life, and NWK-1 is the first meaningful new structure tested near the Arar production cluster under the company’s current PSC term.

What follows here separates what the test results actually show from what the block’s infrastructure adds, and lays out what still needs to be resolved before this becomes a development. That is enough to weigh the announcement on its own terms.

What the NWK-1 well found: two pay zones and an unexpected oil hit

The well was drilled to a total depth of roughly 6,700 ft (approximately 2,000 m) in the Arar block, about 15 km northeast of the Arar production cluster. Its primary target was gas and condensate in the Upper Kais Formation. The upper interval delivered exactly that.

Headline result, upper Upper Kais interval Approximately 4.2 million ft3/day of gas, plus 192 b/d of condensate.

That is the primary gas-condensate case, confirmed. But the well had more to give than the headline suggested.

The lower interval of the Upper Kais zone flowed gas at rates between 1.6 million and 2.7 million ft3/day, accompanied by 40-109 b/d of oil. Oil production from this zone was not part of the original well design. Its appearance is the genuine surprise of the announcement, and it adds a second commercial fluid stream to a well that was drilled as a gas-condensate target.

Then came the disappointment. The deeper exploration objective, the Lower Kais zone, yielded only formation water during testing and was sealed and decommissioned, removing that layer of optionality from the story.

Here is how the two productive intervals compare:

The dual-zone outcome, disclosed via SGX filing on 1 September 2026, tells you the well delivered more commercial flexibility than a single gas-condensate target would have. The narrower oil range in the lower zone and the water-bearing deeper interval both signal that the resource picture is still being defined, not settled.

The Kepala Burung block: why existing infrastructure shapes what this discovery is worth

Take the same flow rates and drop them into a greenfield location, and they would be worth far less. What lifts the value of NWK-1 is where it sits.

Infrastructure gaps are one of the primary reasons small oil discoveries in remote basins never reach production, and the Kepala Burung block’s existing terminal capacity is what separates NWK-1 from the many Southeast Asian wells that confirm hydrocarbons but lack a viable evacuation route.

The Kepala Burung PSC is a mature, heavily developed block. Drilling began in 1972, and cumulative output has surpassed 360 million barrels of oil and 270 billion ft3 of gas. The Walio field alone contributes more than 50% of total block oil production, with Petrogas (Basin) holding a 70% working interest and Pertamina the remaining 30%.

The block’s monetisation engine is the Kasim Marine Terminal (KMT), which sits within the contract area. Crude from across the block is commingled there and marketed as the “Walio Mix” blend, then treated, stored, and moved on to Pertamina’s adjacent RU-VII Kasim refinery or loaded onto tankers.

The KMT’s core functions include:

• Crude treating and storage for the whole block
• Pipeline transfer to the RU-VII Kasim refinery
• Tanker loading via the terminal pier for domestic and export sale
• Third-party throughput handling
• Gas dispatch for internal power generation and sales to supply Sorong city, the largest urban centre in Southwest Papua

For you as a reader assessing the timeline, that infrastructure is the point. Any oil volumes confirmed at NWK-1 have a ready evacuation route through the KMT and the neighbouring refinery, which strips away the midstream hurdle that usually dominates the commercialisation clock for a discovery of this size.

Redevelopment strategy: in-fill drilling, EOR, and new structures

NWK-1 is not a standalone exploration bet. It fits inside a broader redevelopment programme for an ageing block.

Petrogas has started a chemical enhanced oil recovery (CEOR) pilot at Walio, a technique that injects chemicals to push additional crude toward production wells, targeting the mature Kais carbonate reservoir that has been producing for over four decades.

Chemical enhanced oil recovery techniques have advanced considerably in carbonate reservoirs similar to the Kais formation, where chemical injection can unlock residual oil that primary and secondary recovery methods leave behind in the pore structure.

Alongside that, the company is combining in-fill drilling, production optimisation, and the testing of new structures such as NWK-1 to add reserves and extend the working area’s life. Operating under a 20-year PSC term, the company has the runway to pursue that longer-dated strategy rather than chasing a quick result.

Where NWK-1 sits in Indonesia’s broader gas-condensate push

The NWK-1 result is not an isolated event. It is part of a deliberate pattern of independents and mid-caps advancing gas-condensate projects across Indonesian PSCs, and that pattern gives you a reference point for what commercialisation can look like.

The clearest precedent for speed is Jadestone Energy’s Akatara project in the Lemang PSC. Jadestone reached condensate production in June 2024 and commercial gas sales in July 2024, backed by 2P gross reserves of 25.5 mmboe (83 Bscf sales gas plus 11.7 mmbbl of LPG and condensate). That timeline tells you a well-positioned independent with existing infrastructure can move from discovery to commercial output in under two years, the optimistic scenario the NWK-1 results now put within reach if appraisal confirms the resource.

Other recent Indonesian PSC results provide scale context:

• Jadestone Energy, Akatara (Lemang PSC): condensate first production June 2024, commercial gas July 2024, 25.5 mmboe 2P reserves
• Mubadala Energy, Tangkulo-1 (South Andaman PSC): drill stem tests of 47 MMcf/d gas and 1,300 b/d condensate, lifting block potential to about 8 Tcf
• Eni, Geliga-1 (Ganal block): a large discovery estimated at 5 Tcf of gas and 300 million barrels of condensate

NWK-1’s scale sits closest to Akatara rather than the larger offshore finds, which is why the Jadestone monetisation path is the most useful comparison.

The wider investment backdrop supports the trend.

Indonesian upstream investment Reached approximately US$13.7 billion in 2023, up roughly 12% on 2022.

One structural constraint applies to every gas discovery in an Indonesian PSC: the domestic market obligation (DMO), which requires contractors to supply up to 25% of entitlement gas to domestic buyers. That rule is directly relevant here, because Kepala Burung already sells gas to supply Sorong city, giving NWK-1 gas a partial domestic outlet built in.

Appraisal hurdles and what still needs to go right

Promising well results and a commercial development are not the same thing, and the gap between them is where the real work sits.

The gap between promising flow rates and a sanctioned development is a recurring theme in Indonesian PSC exploration, where commercial viability challenges around gas monetisation, regulatory approvals, and offtake structure have stalled projects that produced strong initial well results.

RHP’s own Board has been explicit on this. The company has stated that no conclusion regarding commerciality, recoverable reserves, or future production performance should be inferred until the well testing programme and subsequent technical evaluation are complete.

Board caution on commerciality Subsurface parameters, including productivity, connected volume, and fluid phase behaviour, remain uncertain until the technical evaluation is finished.

The subsurface risk is local, not theoretical. The earlier Karim-1 exploration well in the same Arar region encountered water-bearing primary targets and only trace-to-moderate oil indications in secondary zones. At NWK-1 itself, the Lower Kais interval produced only formation water and was decommissioned. Both are reminders that promising structures in this region do not always deliver.

The four risk categories that still need to resolve are:

• Subsurface and appraisal risk: connected volume, fluid behaviour, and reservoir productivity are still being characterised, and the Karim-1 result shows local structures can disappoint.
• Gas monetisation challenge: oil has a route through the KMT, but significant new gas beyond current Sorong supply could require fresh midstream investment or expanded offtake agreements.
• Regulatory and legal complexity: DMO compliance, mandatory local participating-interest transfers, and PSC approvals all apply to any development decision.
• Operational and community risk: the NWK-1 spud was delayed in early 2026 by heavy rainfall and road blockades by local residents, notified via SGX filing on 24 January 2026, and similar disruption could hit appraisal drilling.

RHP’s stated next step is further reservoir evaluation to determine a suitable development pathway for the Northwest Klagagi field. That appraisal decision, not the current flow rates, is the true test of whether this is a development-ready resource or a further exploration question.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Past performance does not guarantee future results, and financial projections are subject to market conditions and various risk factors.

What the NWK-1 result changes for RH Petrogas, and what it does not

The two-zone result works as proof of concept for the Northwest Klagagi structure. The primary gas-condensate objective was met, and the unexpected oil zone adds commercial optionality without redrawing the development path.

What it does not do is change the near-term picture. This creates an appraisal option, not a production addition. RHP’s current output profile and financial position are unaltered until reservoir evaluation and development planning for the field either confirm a new producing asset or file it as another data point in the block’s exploration inventory.

Two facts frame the balance. The 20-year PSC term and the KMT’s existing capacity mean the company has both time and infrastructure on its side. Any development decision, though, will still need SKK Migas engagement and careful community-relations management.

The market context sharpens the read. Shares in RH Petrogas (ticker T13 / RHPG) traded at roughly SGD 0.166 on 1 September 2026, near the lower end of a 52-week range of SGD 0.140-0.280. That positioning tells you the market had not priced in a discovery before the announcement, so the NWK-1 result represents genuinely new information rather than confirmation of an existing expectation. The next signal to watch is appraisal progress.

Upstream oil and gas investment in Southeast Asian PSC blocks involves a distinct risk-return profile shaped by production sharing terms, state participation rights, and the tension between near-term appraisal costs and longer-dated monetisation timelines that characterise discoveries of this scale.

These statements are speculative and subject to change based on market developments and company performance.