In this exclusive interview, The Energy Circle by IN-VR spoke with S&P Global Commodity Insights about the Timor Sea’s strong subsurface fundamentals and commercialization hurdles, pre-FID priorities for Kuda Tasi–Jahal, APAC precedents for early production and investor-friendly terms, the role of shipping/trade analytics and price scenarios in project economics, and the key signals that would mark a bankable, multi-project future for Timor-Leste.
Q1. From S&P’s regional upstream research and basin screening work, how would you characterize the Timor-Sea basin’s commercial potential today — and how does it compare with other Asia-Pacific frontier and near-field plays you cover?
A: The offshore Bonaparte Basin, including the Sahul Platform and Nancar Trough, covers Timor-Sea and it continues to demonstrate large commercial potential for hydrocarbons. The area is characterized by proven petroleum systems that feature high-quality and diverse reservoir characteristics.
Of the discoveries now located in the jurisdiction of offshore Timor-Leste, approximately 90% of the recoverable resources are located in just four fields. More than 95% of the discovered resources were made before the turn of the century and prior to the Timor-Leste–Australia maritime boundary shift in 2019. This includes significant undeveloped resources such as Sunrise, Chuditch, and Kuda Tasi. While the path to monetization has been complex, it still indicates potential for future growth. To date, the key Late Jurassic to Early Cretaceous proven clastic and carbonate reservoirs have supported previous oil and gas production.
Although their proximity to established and emerging energy markets is a significant advantage, future developments face commercialization challenges. Like other Asia-Pacific (APAC) region frontier areas, the Timor Sea lacks extensive established infrastructure. However, its closeness to existing markets remains a crucial factor for attracting new investment. The commercialization of both proven and new resources will depend on the specific commodity, the resource size, and the potential for aggregate production scenarios—challenges common across many emerging or infrastructure-deficient basins in APAC.
While APAC basins exhibit frontier potential mostly in offshore and deepwater regions, Timor-Leste exploration maturity has been weighted to distinct offshore areas where most of the 80+ NFWs across the region have been spudded. Along with a large area of the region remaining unlicensed, both onshore and offshore areas remain devoid of well penetrations, while significant prospectivity has been mapped over these areas from seismic data.
In the adjacent offshore Browse Basin, it took 40 years for the commercial potential to be realized despite having recoverable resources exceeding 7,800 million barrels of oil equivalent (MMboe). It was only after final investment decisions (FIDs) were made for the Prelude and Ichthys LNG projects that the basin's stranded position was overcome.
In summary, the Timor Sea area possess key subsurface features conducive to hydrocarbon accumulation, enhancing its appeal for exploration. Like many frontier or immature basins, realizing commercial production would require stable legal and attractive fiscal regimes, investment in infrastructure and effective partnerships between the host government and operating companies.
Q2. S&P’s Upstream Solutions combines data, valuation and market foresight used by investors and operators. For a resource holder/operator like Finder Energy advancing Kuda Tasi–Jahal, what are the top three datasets, analytics or valuation inputs you would expect them (or their partners) to prioritize before an FID?
A: There are certainly numerous considerations to be made before taking FID on any project, especially when an asset, such as Kuda Tasi-Jahal, has been dormant for a number of years—is this the right time for development? Since discovery, a multitude of situational changes have occurred—neighboring fields have run through entire production cycles, the oil price has fluctuated by approximately US$130/bbl, and the ownership of the fields has changed. Yet, Finder Energy is now in a position to secure its first production through an accelerated Front-end Engineering Design (FEED)-FID program, which could be the first new production for Timor-Leste since the startup of Kitan in 2011.
For fields that have not seen an appraisal program in the past 20 years, establishing an understanding of the geological model, including reservoir characterization, will be important. Without knowing the development potential from the bottom up, the other factors are perhaps irrelevant.
Utilizing available seismic data, in this case, the 20-year-old Ikan 3D survey, enables a fast-tracked approach to refining the geological model. Improving the data quality through reprocessing and adding well control is key to reaffirming geological concepts initially confirmed in 1996. Reviewing successful production test logs will provide hope for upcoming commercial success. However, it is also important to understand the narrative of why an asset was not initially brought into production upon discovery through independent assessments of all available subsurface data.
Particularly considering historic geological modeling from vintage seismic data, modernizing existing data where available can not only lead to a reaffirmation of previous concepts but also aid in derisking further exploration or development considerations. The support of the Autoridade Nacional do Petróleo (ANP) for expensive seismic reprocessing, mapping, and prospectivity assessment in the Timor Sea will improve critical data to bolster geological insights ahead of the next wave of new investment.
A critical component of pre-FID planning for a project like Kuda Tasi–Jahal is a robust sensitivity and risk scenario analysis to understand how shifts in key variables—policy, cost, production rates, or prices—could affect project viability.
On the policy front, potential changes to licensing frameworks, environmental standards, or export terms could materially impact development sequencing, infrastructure selection, and gas marketing strategies, ultimately influencing the project’s commercial outcomes.
Equally important is a clear understanding of cost exposure, particularly in today’s constrained global supply chain, where rig rates, subsea infrastructure costs, and LNG tolling or shipping fees are increasingly volatile and often outside an operator’s control. Price sensitivity analysis remains essential in the current market environment, where geopolitical and macroeconomic uncertainty can drive wide swings in oil and gas prices. Over the next few years, the S&P Global Upstream Capital Costs Index, referenced to a 2010 baseline, forecasts a three to four percent per year increase in costs from the service sector. The increases reflect limited supply chain capacity under a delayed energy transition scenario and global trade disputes. Beyond understanding exposure, companies should define mitigation strategies or contingency plans for each high-impact variable—ensuring that projects remain resilient and economically viable under a range of adverse conditions.
Good luck to Finder Energy and joint venture TIMOR GAP as they build towards seeing Timor-Leste through to another realm of offshore production.
Q3. Timor-Leste faces the twin tasks of accelerating early production while building local capacity and fiscal resilience. From your work advising E&P strategy in the region, what commercial structures (e.g., phased early-production, production sharing tweaks, local content models) have you seen balance speed to first oil with host-country benefits? Are there APAC precedents Timor-Leste should look at?
A: Attracting upstream investments and finding strategic partners would be key for Timor-Leste in rejuvenating hydrocarbon production, which will then support building local capacity. The government's role in achieving this will be critical, and there are lessons to be drawn from neighboring countries in the region that have either rejuvenated or are working their way back to spurring upstream investment.
Malaysia’s adoption of fit-for-purpose fiscal terms could be considered, as this has attracted diverse companies to take on exploration blocks in both mature and frontier basins. Acreage offers were supported by better data, including new regional multi-client 3D seismic data and a data repository system allowing re-evaluation of potential in these areas. Companies have also taken on the challenge of developing clusters of marginal fields by introducing Small Field Asset (SFA) terms in 2020, promoting cost-efficient development models and quicker investment returns. Three Discovered Resource Opportunity (DRO) clusters have already achieved FID, with early monetization via nearby infrastructure.
The role of the NOC in supporting fast-track gas developments with other players in the country is likewise worth noting. Discoveries made in the mature but still prolific Central Luconia Province over the last 10 years have been pushed for development in collaboration with PETRONAS. Key discoveries from 2014 to 2020 by SapuraOMV, which TotalEnergies has acquired, saw fields developed in two key clusters. Phase 1 of the development achieved production six years after the discoveries were made. Shell’s Rosmari-Marjoram fields, the first high H2S development in the basin, target first gas in 2026. Looking at an emerging basin with no established infrastructure, like the West Luconia Province, the Kenyalang Cluster is an example of finding a partner following post-drilling success. The discoveries in this cluster were made by PETRONAS Carigali during its drilling campaign conducted in 2023-2024. TotalEnergies has recently farmed in to focus on field development and potential resource upside adjacent to the cluster.
Adoption of key technology like small-scale FLNG has unlocked previously stranded resources, particularly in the Sabah area. There are two operating FLNGs, and a third one is scheduled to be Ready for Start-up (RFSU) by the end of 2026, followed by commercial operation in the second half of 2027.
Collaboration between national oil companies (NOCs), international operators, and local companies will facilitate knowledge transfer and capacity building. Incorporating local companies into the supply chain can be challenging. It may initially reduce operational efficiencies, but building partnerships can overcome these challenges, establishing a positive relationship that benefits local content delivery and operational effectiveness.
Jumping to Indonesia, the country’s move to adapt to industry feedback has rejuvenated interest. Bringing back the production sharing contract option on blocks offered for bidding and, at the same time, introducing improvements in profit sharing has driven recent awards. Further changes are still being implemented, like simplifying the gross split mechanism. The country also has several examples of early development schemes that supported operators in understanding subsurface complexities and planning for full development while generating early revenue. The Banyu Urip development in onshore East Java demonstrates that production can ramp up significantly over time, with ExxonMobil's optimization efforts leading to increased production from 20,000 b/d to over 220,000 b/d. Mubadala is looking for an early development approach on its recent frontier exploration success in the deep water North Sumatra Basin, where we could see the Tangkulo field being developed first, with gas supplying the domestic market.
Other countries in the region are also moving to re-attract upstream investment. Vietnam has recently introduced incentives in its production sharing contracts. Higher cost-recovery ceilings (up to 80–90%) and lower income taxes are granted for frontier or technically challenging developments. As production scales and profitability improves, fiscal terms tighten through progressive royalty rates and sliding profit-oil splits, allowing the state to capture a larger share of value over the project's life.
Phased early production agreements or phased production development schemes can be implemented to help operators build an understanding of subsurface complexities and plan for full development while generating early revenue. There are many scenarios for either early or staged developments, like planning for early liquids offtake to allow additional time to build a larger gas resource through exploration or aggregation, improving later project economics.
In Vietnam, the government has made several adjustments to its Production Sharing Contracts (PSCs) over the years to enhance their attractiveness to foreign investors while ensuring substantial government revenue. One notable change was the introduction of more flexible profit-sharing arrangements in the revised PSCs, allowing for a higher share of production to be allocated to the government as production levels increase.
Regulators generally trade fiscal generosity in the early years for a stronger state take as projects mature. This sequencing attracts capital to bring hydrocarbons online quickly while ensuring the host country benefits from production growth, high prices, or large reserve discoveries. Vietnam applies this approach through its incentive and special incentives PSCs, where higher cost-recovery ceilings (up to 80–90%) and lower income taxes are granted for frontier or technically challenging developments. As production scales and profitability improves, fiscal terms tighten through progressive royalty rates and sliding profit-oil splits, allowing the state to capture a larger share of value over the project's life.
By adopting various commercial structures, Timor-Leste can effectively balance the urgency of early production with the need for sustainable development and fiscal resilience. These approaches not only support immediate economic benefits but also lay the groundwork for long-term growth and stability in the region.
Collaboration between national oil companies (NOCs), international operators, and local companies will also facilitate knowledge transfer and capacity building. Incorporating local companies into the supply chain can be challenging and may initially reduce operational efficiencies, but building partnerships can overcome these challenges, establishing a positive relationship that benefits both local content delivery and operational effectiveness.
Q4. Market access, shipping logistics and price & demand outlooks shape project economics. How do S&P’s shipping / trade analytics and oil price scenario work feed into upstream decisions for shallow-water developments in small states like Timor-Leste?
A: These components are critical in shaping project economics, particularly for shallow-water developments. Shipping and trade analytics, along with oil price scenario forecasts, provide essential data informing upstream decision-making for offshore developments in Timor-Leste. By leveraging these insights, operators can optimize project economics, enhance market positioning, and improve the chances of successful project execution.
If integrated into development decisions early, shipping and trade analytics can help identify the most cost-effective routes and shipping options, enabling operators to make informed decisions about supply chain management and distribution.
Oil price scenario forecasts are crucial. This assessment is important in almost all aspects of development planning, regardless of the setting or situation. Oil price forecasts help operators assess the potential economic viability of projects under different market conditions. By analyzing various price scenarios, companies can conduct sensitivity analyses to understand how fluctuations in oil prices may impact revenue and profitability. This information is crucial for investment decisions, allowing operators to evaluate whether expected returns justify the risks associated with exploration and production in shallow-water environments.
Understanding future demand for oil and gas is essential for strategic planning. Shipping and trade analytics provide insights into regional and global demand trends, informing decisions about production levels and target markets. For instance, if demand for natural gas in Asia is projected to rise, Timor-Leste can position itself to supply that demand, enhancing the attractiveness of its offshore resources.
Efficient access to key markets is vital for the success of upstream projects. Analytics can help identify potential buyers and market dynamics, allowing operators to strategize marketing efforts and negotiate favorable terms. Additionally, understanding regulatory frameworks and trade agreements can facilitate smoother market entry.
In summary, shipping and trade analytics, along with oil price scenario forecasts, provide essential data informing upstream decision-making for shallow-water developments in Timor-Leste. By leveraging these insights, operators can optimize project economics, enhance market positioning, and improve the chances of successful project execution.
Q5. Finally, looking 5–10 years ahead, what signals would you advise international investors and Timor-Leste policymakers to monitor most closely that would indicate the Timor Sea is maturing into a bankable series of developments (rather than a one-off discovery)?
A: Essential for Timor-Leste’s future development will be the next ‘kickoff point’ and visible progression to entice new investors. The kickoff point could be an event or activity that sparks interest in the international market, such as a planned high-impact well or farm-out, bringing in a major player with the capacity to support an extensive exploration program. That kickoff point could also be a new project FID, solidifying a new investment position that would highlight Timor-Leste's readiness to sanction projects, a situation not seen since 2010. Key progression would involve new facilities and infrastructure to support multi-phase developments and offer third-party tie-back options for maturing financial commitments for marginal projects.
Another example would be a gas development at the Timor Resources assets in the onshore Timor Basin to establish a domestic market for gas-fired power generation. This could offer a faster turnaround time than an offshore development and assist in derisking the commercial aspects of a nearshore development. Thus, it would provide an impetus for new exploration. It is certainly easier to state these points than to materialize action, but without a key activity or continued progression, there is a risk that investment opportunities could be missed as operators look to grow through global portfolios.
Looking ahead, a sustained increase in exploration drilling and seismic surveys would indicate growing confidence among operators and investors. Monitoring the number of active exploration licenses, the success rates of new discoveries, and the involvement of major international oil companies can signal robust interest in the region's potential.
For policymakers, setting up for the future begins in the present with the need for an adequate, stable, and transparent regulatory environment to attract and retain investment. Observing how neighboring fiscal and regulatory terms are being adapted to increase investment and feeding back the outcomes could be a good indicator.
The extent to which local companies and the workforce are integrated into the oil and gas sector will be a significant indicator of long-term sustainability. Monitoring initiatives aimed at enhancing local content, training programs, and partnerships delivered by international operators should be carried out.
By monitoring these signals, international investors and Timor-Leste policymakers can gain valuable insights into the maturation of the Timor Sea, fostering a more sustainable and prosperous energy future for the region.
Stay tuned to The Energy Circle by IN-VR for the latest updates on the global energy industry and exclusive insights from its leading voices.
