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The Joint Supervisory Body (JSB) has endorsed the transfer of key revenue-raising powers from the Papua New Guinea National Government to the Autonomous Bougainville Government (ABG), with revenues generated from fisheries, mining, forestry, land and other relevant taxes to be handed over by 31 December 2026. The resolution was adopted during the JSB meeting at Melanesian Haus in Port Moresby this week, co-chaired by Prime Minister James Marape and ABG President Ishmael Toroama. The JSB also endorsed the ABG's proposals on taxation, revenue streams, statutory fees and related fiscal powers, as well as measures to strengthen fisheries governance and marine resource benefit-sharing. To implement the agreement, the Chief Secretaries of both governments were directed to oversee and coordinate all technical engagements covering taxation, customs and excise, fisheries, statutory fees and other fiscal and economic matters affecting Bougainville. They have also been tasked with submitting a joint progress report at a future JSB meeting. In his address to the meeting, Toroama described the transfer of fiscal powers as part of Bougainville's transition beyond autonomy and towards greater self-government, saying the region's political position had been shaped through extensive consultations and endorsed by its leadership. He said Bougainville had honoured every resolution reached under the peace process, including the Bougainville Peace Agreement, the Wabag Roadmap, the Era Kone Covenant and previous JSB resolutions, and called on both governments to continue implementing the Joint Consultation Report and the Melanesian Framework in good faith. Toroama also reaffirmed Bougainville's position that the 2019 independence referendum, in which 97.7% of voters backed independence, should remain the basis for the region's political future. "We do not need a 'clear pathway to revisit the question' — the question has been asked, answered, and sealed in ink and blood," he said, rejecting suggestions that the referendum result could be revisited through future political processes. He urged both governments to uphold the integrity of the Bougainville peace process, warning that any departure from jointly agreed commitments would attract international scrutiny. "Our work today continues under the watchful, supportive eyes of our global partners," Toroama said, acknowledging the United Nations' continuing role in supporting the implementation of the post-referendum process. The latest JSB resolution marks a significant step in expanding Bougainville's fiscal autonomy, with the transfer of revenue powers expected to strengthen the ABG's capacity to manage its own economic affairs ahead of the agreed end-2026 deadline.

The Autonomous Bougainville Government has removed 30 Chinese nationals from a suspected illegal mining site in Kopani following a joint enforcement operation involving police, immigration and mining authorities. The operation was conducted at about 4 a.m. Sunday by officers from the Bougainville Police Service in Arawa and Buka, together with officials from Immigration and the ABG Department of Mining and Petroleum. The 30 Chinese nationals were extracted from the site, where they were allegedly involved in unauthorized mining activities. Preliminary immigration checks identified issues with the nationals’ immigration documentation and status in relation to their presence and activities in Bougainville, according to the ABG. Their passports were confiscated pending further action. Under immigration directions, the nationals have been ordered to leave Bougainville within five days and travel to Port Moresby for further processing at Bomana. The costs of their travel will be borne by people associated with the unauthorized mining operation, the ABG said. President and Minister for Mining and Petroleum Ishmael Toroama said the operation demonstrated his government’s determination to protect Bougainville’s mineral resources, environment and communities from unlawful exploitation. “Our resources belong to the people of Bougainville and must be developed responsibly, lawfully and for the benefit of our people. Anyone who comes into Bougainville must respect the applicable laws. Where those laws are breached, necessary enforcement action will be taken,” Toroama said. Equipment linked to the suspected illegal mining operation remains secured at the site under police instructions pending further enforcement action. Toroama said the ABG was also pursuing amendments to strengthen offense, prosecution and penalty provisions under Bougainville’s mining laws. The government is appealing similar unauthorized mining cases in which court decisions have been unfavorable to the prosecution, seeking further judicial consideration and clarification of relevant provisions of the mining legislation. In the meantime, authorities are using immigration, environmental and other applicable laws to address the current case and other suspected unauthorized mining activities. Illegal mining may also constitute separate offenses under environmental legislation, including the Environment Act 2000, where mining is carried out without required environmental approvals or causes unlawful environmental harm, the ABG said. “This is not simply a mining law issue. Persons involved in illegal mining may expose themselves to investigation and prosecution under mining, environmental, immigration and other applicable laws,” Toroama said. “We will use the legal mechanisms available to protect Bougainville, our people, our land and our resources.” Investigations are continuing and will also examine the involvement of local people who may have facilitated, financed, organized, supported or otherwise participated in the suspected illegal mining activities. Toroama thanked police, immigration and mining officials involved in the operation and said the government would continue to support coordinated enforcement against illegal activities in Bougainville.

Autonomous Bougainville Government President and Mining & Petroleum Minister Ishmael Toroama has issued the LSML-01 Preparatory Works and Feasibility Commencement Certificate to Bougainville Minerals Ltd, allowing initial technical and feasibility activities to begin for the proposed redevelopment of the Panguna mine. The certificate, presented to Bougainville Minerals Ltd in the presence of its approved development partner, Lloyds Panguna Metals & Energy Ltd, was issued under the special redevelopment pathway established by the Bougainville Mining (Amendment) Act 2026. The commencement certificate authorises Bougainville Minerals, through Lloyds Panguna Metals & Energy, to undertake an approved programme of preparatory works and feasibility studies for the Panguna project. The activities include technical, engineering, environmental, social and economic assessments needed to evaluate and plan the proposed redevelopment of the mine. The Autonomous Bougainville Government said the certificate does not permit mine construction or commercial production. Those phases will require separate statutory approvals and additional commencement certificates. Toroama said the issuance marks an important milestone in the redevelopment process while reaffirming the government's commitment to responsible resource development under Bougainville's legal framework. "The issuance of this Commencement Certificate today marks the beginning of a new chapter for Bougainville. It reflects our confidence in our own laws, our institutions and our ability to responsibly manage our natural resources," Toroama said. "The redevelopment of Panguna will proceed one step at a time—guided by transparency, accountability, respect for our landowners and communities, and a shared commitment to ensuring that our mineral wealth creates lasting opportunities and prosperity for all Bougainvilleans," he added.

The Sepik Development Project (SDP) continues to record strong progress in stakeholder engagement while expanding employment opportunities for Papua New Guineans, with a clear focus on benefiting communities in the Sepik region. Project representatives from the community affairs team, whose dedicated role is to meet with and listen to local communities, recently visited near-mine communities, including those in the Upper Sepik, where they held constructive engagement sessions about project plans and new opportunities. The consultative engagement is part of an ongoing schedule of positive engagement with landowners, local communities, government agencies, and other key stakeholders, reflecting the Project’s commitment to transparency, partnership, and responsible resource development. Country Manager Dr Joel Hamago said the strength of stakeholder relationships established to date demonstrates the Project’s long-term commitment to Papua New Guinea. “We are encouraged by the collaborative approach we are seeing on the ground, and we remain committed to open dialogue and mutual respect as the Project progresses,” Dr Hamago said. “Meaningful engagement with our host communities, based on transparency and accurate information, is central to how we operate.” Dr Hamago called on opponents of the Project to adopt the same commitment to accuracy and honesty in their actions. “It is disappointing to see a recent media publication where Project Sepik continues to misrepresent the outcome of the SDP’s recent engagement with Sepik communities via the OECD’s AusNCP referral process, where an independent examiner confirmed our compliance with OECD guidelines in relation to stakeholder engagement on this project.” Dr Hamago said community engagement activities would continue. “While we have had an overwhelmingly positive response from communities, which value the level of engagement and the future opportunities from the Development, we understand that many people still have concerns and questions, which is why we will continue to listen as we consult with them." Employment Growth and Opportunities for Sepik Communities As activities continue to advance, the Sepik Development Project has opened a number of new employment opportunities across various roles, which are currently advertised on the Project’s official LinkedIn page. In line with the Project’s localisation strategy, priority will be given to suitably qualified applicants from the Sepik region, ensuring local communities are directly involved in and benefit from Project development. “Our employment strategy is deliberately focused on local participation,” Dr Hamago said. “Wherever possible, we want people from the Sepik to take up these roles, gain valuable skills, and become part of the Project’s journey from the early stages.” Supporting PNG’s Local and National Content Agenda The Sepik Development Project strongly supports the Papua New Guinea Government’s drive to increase local and national content within major resource developments. Through targeted recruitment, training, and skills development, the Project aims to create sustainable employment outcomes and contribute to long-term national capacity building. “This Project is about more than just mining. It is also an infrastructure project with rippling opportunities,” Dr Hamago said. “It is about building capability, supporting PNG talent, and ensuring that Papua New Guineans are well positioned to participate meaningfully in major developments, both now and into the future.” How to Apply Interested applicants are encouraged to view current vacancies and application details via the Frieda River Limited LinkedIn page. Applicants should carefully review role requirements and ensure their qualifications and experience align with the advertised positions. The Frieda River Project will continue to provide regular updates on stakeholder engagement, employment opportunities, and Project milestones. Frieda River Limited is the proponent of the Sepik Development Project (SDP) in Papua New Guinea. The SDP comprises four integrated components: the Sepik Infrastructure Project (SIP), the Frieda River Copper-Gold Project (FRCGP), the Frieda River Hydroelectric Project (FRHEP), and the Sepik Power Grid Project (SPGP). The Project is designed to deliver enabling infrastructure, including power generation and transmission, road access, airport and port facilities, supported through private investment. During operations, the SDP is expected to create approximately 2,500 direct jobs, with a target of 93 per cent national employment, and generate more than 30,000 indirect employment opportunities. The Project incorporates engineered tailings and water management systems, as well as a hydroelectric power solution intended to reduce operational emissions and support environmental management objectives, including protection of the Sepik River system. Frieda River Limited is a significant subsidiary of the PanAust Limited Group. Along with pre-development opportunities in Papua New Guinea operations, PanAust Limited also owns Phu Bia Mining, an award-winning dual operation in Laos, and has development opportunities in Chile. An Australian-incorporated company, PanAust is owned by Guangdong Rising H.K. (Holding) Limited, which is a wholly owned subsidiary of Guangdong Rising Holding Group Co., Ltd. (GDRH). GDRH is a Chinese state-owned company regulated under the State-owned Assets Supervision and Administration Commission of the People’s Government of Guangdong Province in China.

The New Ireland Provincial Government has committed K1 million to a new partnership with the Fresh Produce Development Authority (FPDA), aiming to transform agriculture into a stronger economic driver while improving food security and increasing household incomes across the province. The investment is part of a three-year Memorandum of Understanding (MoU) signed by New Ireland Governor Byron Chan and FPDA Chief Executive Officer Mark Worinu in Port Moresby on July 15. Under the agreement, the provincial government will contribute K1 million in the first year, followed by K500,000 annually over the next two years, subject to project requirements. In addition to funding, it will provide land, project personnel and other resources to support implementation. The partnership is expected to strengthen New Ireland's agricultural value chain by expanding commercial horticulture, improving market access and investing in infrastructure to reduce post-harvest losses. Governor Chan said agriculture has the potential to become a key pillar of the province's economic diversification strategy, creating sustainable income opportunities for rural communities while reducing reliance on traditional industries. "Agriculture remains the backbone of many of our communities. This partnership is about giving our farmers the support they need to move beyond subsistence farming and become successful commercial producers," he said. To support that goal, the program will provide agricultural extension services, farmer training and technical assistance while establishing cool storage facilities in Kavieng and Namatanai to improve the quality of fresh produce reaching local and national markets. The provincial government will also identify State land for the establishment of a certified English potato seed farm, together with a horticultural nursery and germplasm collection facility to ensure a reliable supply of high-quality planting materials. Governor Chan said these investments would help build a productive and commercially competitive agricultural sector capable of supporting long-term economic growth. "We are investing in infrastructure that will continue serving our farmers well into the future. Cold storage, quality seed production and modern farming techniques will improve productivity and give farmers greater confidence to expand their operations," he said. He said New Ireland's favourable climate, fertile soils and growing domestic demand for fresh produce position the province to become a major contributor to Papua New Guinea's horticulture industry. "Our vision is not simply to produce more food. We want to create an agricultural economy where farmers are earning sustainable incomes, supplying quality produce to markets and creating employment opportunities within their own communities," he said. FPDA Chief Executive Officer Mark Worinu said the partnership would focus on developing modern production systems and strengthening agricultural supply chains, particularly for English potatoes. "New Ireland has tremendous potential, particularly in English potato production. Through this partnership, we will establish a complete production, distribution and marketing system while developing a certified potato seed centre at Lelet to supply clean planting material for local farmers," Mr Worinu said. He added that FPDA would also support the production and marketing of bulb onions and other priority horticultural crops to improve household incomes and strengthen food security. Beyond increasing agricultural output, the initiative is expected to deliver wider economic benefits through higher rural incomes, improved productivity and stronger participation by local farmers in formal markets. Governor Chan said the agreement aligns with the Chan-Kolivos Government's broader development agenda of creating sustainable economic opportunities beyond the province's mining and fisheries sectors. He said strengthening agriculture would stimulate local businesses, create jobs and support inclusive economic growth. "Economic development begins in our villages. When farmers have the skills, infrastructure and market opportunities to succeed, entire communities benefit. This partnership is an investment in our people, our land and our future," he said. The project will be jointly administered by the Fresh Produce Development Authority and the New Ireland Provincial Government, with implementation expected to begin immediately.

Papua New Guinea has secured approval for a major biodiversity conservation project under the Global Biodiversity Framework Fund (GBFF), a move expected to strengthen community-led conservation efforts and support the country's commitments under the Kunming-Montreal Global Biodiversity Framework. The project, titled "Empowering Indigenous Peoples and Local Communities for sustainable management and conservation of 700,000 hectares of critical ecosystems in three Highland provinces in Papua New Guinea," will be implemented by the Conservation and Environment Protection Authority (CEPA) in partnership with the Food and Agriculture Organization of the United Nations (FAO). The initiative will support Indigenous Peoples and Local Communities (IPLCs) across Enga, Chimbu and Jiwaka provinces in conserving critical ecosystems while promoting sustainable livelihoods and strengthening customary stewardship systems. The project contributes to Papua New Guinea's efforts to meet global biodiversity targets, including the international goal of conserving at least 30 per cent of the world's land and sea areas by 2030. Papua New Guinea is recognised as one of the world's 17 megadiverse countries, with forests covering about 78 per cent of its land area and hosting species found nowhere else on Earth, including tree kangaroos, long-beaked echidnas and rare birds-of-paradise. Approximately 97 per cent of the country's land remains under customary ownership, placing Indigenous communities at the forefront of conservation efforts. According to CEPA Managing Director Jude Tukuliya, the project underscores the importance of protecting biodiversity and forest ecosystems that communities have relied on for generations. He said Indigenous Peoples and local communities continue to play a crucial role in safeguarding the country's biodiversity and that conservation efforts must integrate traditional knowledge with modern management approaches while supporting economic opportunities for local people. FAO Representative in Papua New Guinea Dr Kachen Wongsathapornchai said conservation initiatives are most effective when they provide tangible benefits to communities. "Protecting biodiversity and sustaining livelihoods go hand in hand. By advancing biodiversity-positive production, we make environmental protection a driver of stronger food systems and rural economies," he said. The project aims to improve the management of more than 272,000 hectares of protected areas and community conservation landscapes, restore 5,000 hectares of degraded ecosystems and promote biodiversity-friendly agricultural practices across 7,000 hectares of farmland. It will also support the recognition of Other Effective Area-Based Conservation Measures (OECMs), develop sustainable financing mechanisms and deliver direct benefits to at least 20,000 people, with women expected to comprise half of all beneficiaries. Project proponents said the initiative would help establish ecological corridors across the Highlands, enabling species to adapt to climate change while encouraging collaboration among communities through shared stewardship of natural resources. The project also seeks to reduce pressure on forests and other ecosystems by supporting economic activities such as agroforestry, organic agriculture, ecotourism and market access for biodiversity-friendly products. Officials said the approval highlights Papua New Guinea's growing role in community-led conservation and demonstrates how Indigenous stewardship can contribute to addressing global biodiversity challenges while creating sustainable development opportunities for local communities.

International Trade and Investment Minister Richard Maru has welcomed R&F Group Chairman and President Li Zhang to Papua New Guinea, expressing confidence that the Chinese property developer will consider major investments in the country's tourism, hospitality and real estate sectors. Li arrived in Port Moresby on Tuesday aboard a private jet after an advance team visited Papua New Guinea two weeks earlier to assess potential investment opportunities. Maru said the government is optimistic the visit will encourage the company to pursue foreign direct investment in the country. R&F Group is one of China's largest property developers and owns more than 80 luxury hotels managed by international brands including Ritz-Carlton, Park Hyatt and Grand Hyatt. The company's portfolio also includes shopping malls and office buildings, with more than 450 projects across more than 145 cities and regions worldwide. Maru said the government hopes the company will invest in several priority developments, including the Paga Hill Estate, Portside Gardens Development and the Duran Farm Housing Project. "We are very confident that the R&F Group is one of China's most serious investors and we look forward to hosting the chairman and his delegation and securing their firm decision to invest in a very big way in our country," Maru said. He added that the government would provide support to facilitate the company's investments if they proceed. The visit comes as Papua New Guinea seeks to build on the recovery of its tourism sector. According to the Papua New Guinea Tourism Promotion Authority, international visitor arrivals rose to 103,881 in 2025, while 92% of surveyed visitors said they would return and 88% indicated they would recommend the destination, reflecting growing confidence in the country's tourism offerings. The Tourism Promotion Authority has also reported continued growth in visitor arrivals and spending, supported by improved air connectivity and targeted international marketing campaigns. 

Resources and/or Reserves The words resources and reserves as applied to the presence of oil and gas deposits are often quite casually used without due regard for their actual meaning. This can clearly mislead people either by grossly exaggerating, or under-estimating the importance of an undrilled prospect, the potential oil and gas production of a field, or even the actual petroleum endowment of a nation. The latter can in turn lead to very serious economic policy errors by a government. A country may be prospective for petroleum accumulations, but being prospective is only a statement of there being the potential for oil and gas to have accumulated into discrete subterranean pools, or accumulations, which may have the potential to be tapped by wells drilled into them. These accumulations have to be found first by field exploration and the drilling of wells, which are not easy tasks. Discovered accumulations then have to be evaluated for the quality of the petroleum that they bear and their extent, and only if they are large enough, might they be considered for commercial recovery of that discovered petroleum. In this discussion, I only discuss conventional oil and gas accumulated in porous and permeable reservoirs, not oil and gas unlocked from less permeable strata by fracturing or gas released from degasification of coal – coal bed methane.      Figure 1: Section through rock strata illustrating subsurface sources of oil and gas, after U.S. Energy Information Administration. Discovery Exactly what constitutes a discovery can be debated for hours by petroleum technocrats.   The Society of Petroleum Engineers defines a discovery as being a “petroleum accumulation where one or several exploratory wells through testing, sampling, and/or logging have demonstrated the existence of a significant quantity of potentially recoverable hydrocarbons and thus have established a known accumulation.” In this context, recoverable means that the hydrocarbons have to demonstrate that they are indeed moveable and are not just immovable residues.  A significant quantity implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume of petroleum as demonstrated by the drilling of wells into the accumulation and for evaluating the potential for future commercial recovery of that petroleum. One should be cautious in the use of the term discovery. Discovery should not be translated into undue expectations of oil and gas field development and petroleum incomes.  Development of any oil and/or gas accumulations only comes as and when there are proven to be adequate recoverable oil and/or gas reserves to warrant the expense and effort of development and production operations. Discovery is the first elemental step towards development, but it is only the initial identification of the accumulation of petroleum, the scope and dimensions of which has to be subsequently ascertained. Interestingly enough, the Papua New Guinea Oil and Gas Act does not define discovery, though it does require the discovery of petroleum to be notified to the Government immediately and details of the same to be provided within three days. The licensee may then be directed to furnish “written particulars of the chemical composition and physical properties of the petroleum; and the subsoil in which the petroleum occurs; and any other pertinent matters.” Typically, the acid test of a discovery has been the testing of the discovery well to see if the petroleum will flow from the subsurface reservoir to the surface, though modern downhole tools can simulate such tests and provide a reasonable understanding of the petroleum content of the discovered accumulation and the ability of its reservoir to permit the flow of its contained fluids.     Figure 2: Testing of the Pasca A-4 well in the Gulf of Papua in 2019, after Twinza Oil Ltd. The evaluation of the results of an exploration well needs to be done most carefully. Full attention to the monitoring of the petroleum operations is essential to preserve the interests of the nation, not that the petroleum companies might mislead the government, but errors of interpretation and judgement do occur.  In one famous case in Papua New Guinea, a well-known operating petroleum company thought that it had made an oil and gas discovery. In an effort to keep up with its fiduciary duties to its shareholders and its Australian Stock Exchange listing requirements, it issued a press release announcing that it had made a significant oil and gas discovery of considerable thickness with well logs showing a gas cap overlying a respectable oil column. The company’s development geologist courteously delivered a copy of the press release to the author at the Government’s Petroleum Division at the Department of Petroleum and Energy together with a set of the well logs (which necessarily excited the author). After ten minutes of cursory review of the logs, the author announced to the company’s development geologist that the company had not discovered any oil or gas, but that the well had rather encountered reservoirs full of water. The press release was suitably endorsed and sent back to the company’s managing director, who was stunned in disbelief.  The company proceeded to evaluate the well the next morning with a full well test of the various supposed hydrocarbon-bearing reservoirs, but the well tests flowed only water. Such was not only a grave disappointment and embarrassment to the company, but also to the Government which naturally would have preferred a discovery.   A Field In conventional petroleum reservoirs, a field is typically an area consisting of a single accumulation or multiple accumulations in a reservoir or reservoirs all grouped on, or related to, the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impermeable rock, laterally by local geologic barriers, or both. Aside from accumulation and reservoir, some jurisdictions use the term pool. In Papua New Guinea, a petroleum pool is defined as a “naturally occurring discrete accumulation of petroleum.”   Figure 3: Map of the Kutubu oil and gas fields: Iagifu-Hedinia, Agogo and Usano, after Oil Search Ltd.       Poor Advice Can be Misleading In one developing country, its foreign expert oil and gas advisers told the government that it had one billion barrels of crude oil. However, that estimate was only an assessment of the overall potential petroleum endowment of the country, if it might be realised through appropriate exploration and discovery. It was a probabilistic estimate based on an assessment of regional geological parameters that are conducive to the formation of petroleum accumulations. It was obviously dependent on the results of exploration which might, or might not take place. Moreover, the advice failed to define whether that was the amount of oil and gas that might be found in situ within the yet-to-be-discovered accumulations, or whether it would be the amount of oil and gas that might be recoverable, either technically or economically. Alas oil, as we all know, is viscous and sticky, and does not flow easily. It also requires energy to flow to the surface, so only a proportion of all subterranean oil discovered is ever recovered. That estimate of the country’s oil endowment also only had a 50% probability. Subsequent exploration by oil and gas companies found just several accumulations of crude oil amounting to an aggregate 200 million barrels of oil-in-place. Oil-in-place is the petroleum that exists originally in naturally occurring accumulations, discovered and undiscovered, before production begins. However, the discovered oil was of high viscosity and density, and only 9% was found to be actually recoverable and potentially able to yield 18 million barrels of actual oil production for sale and use. Politically, the President of the country had staked his national policies on the cited one billion barrels by multiplying that quantity by the then current price of crude oil of US$ 50 per barrel. Thus, he contemplated having a massive US$ 50 billion contribution to the nation’s economy, and maintaining his popularity and position based on such. He told the people that the country would become a member of OPEC and everyone would have cheap gasoline and diesel. However, the reality was that the discovered recoverable 18 million barrels was quite difficult to win from the ground and the development and operating costs amounted to US$ 30 per barrel, leading to a net value of subsequent oil production being only US$ 20 per barrel for a total value of just US$ 360 million. The President then realised that the Government’s Production Sharing Contract more or less allowed the oil companies to keep 50% of the net value of the produced crude, so his government got just US$ 180 million. And this was spread out over twenty years providing an average income to the Government of just U$ 9 million per year, a far cry from the spectacular windfall of US$ 50 billion. The President was accused of misleading the people and was not re-elected in subsequent national elections. There is no need for such grave errors. It is the duty of the petroleum technocrat, specialist or expert, be he or she: an adviser, a government official, or a company official to advise non-technical people appropriately, and with great caution. Politicians and others have their expertise, and we petroleum folks have ours; it is our job to communicate our findings to others with professional care and diligence. In one West African nation, the author once had to tell the President’s Adviser that she was not qualified to talk about the potential oil reserves that some international company had been promoting to her boss, making the President overly exuberant and excited about future oil production. She was alarmed and annoyed when told that the country had no petroleum reserves, but only prospective petroleum resources that had yet to be discovered, may be. Some ten years later, those wells have yet to be drilled, and the country still has no proven oil reserves. On another occasion in Papua New Guinea, when Chairing the Opening Ceremony of the Second PNG Petroleum Convention in May 1993, the author had to carefully and cautiously advise the then Prime Minister, the Rt. Hon. Paius Wingti, PC (next to whom, the author was sitting) that the enormous Indonesian gas reserve figures being talked about by our guest keynote speaker, Ir. Suyitno Patmosukismo, the then Director General of Indonesia’s Ditjen MIGAS, (an abbreviation for Minyak dan Gas Bumi, or Oil and Gas, and the State regulator of oil and gas) were not actual proven recoverable volumes of gas, but probabilistic estimates of potential undiscovered resources.  This put our modest, but conservatively estimated proven recoverable gas resource identified by that time in perspective, and we felt less humbled! The Prime Minister was grateful, and the author had done his duty.   Figure 4: Extract from the Programme of the Second PNG Petroleum Convention, May 1993 The mainstream media (newspapers, television and radio) often make mistakes in talking and writing about oil and gas resources and reserves, often needing specialist technical correction after promoting public misunderstanding. Sensational news sells better, one supposes.  I shall not dwell on the many inaccuracies of social media in these matters. Within the petroleum industry, we may also sometimes find speculation, especially by smaller oil and gas exploration companies that wish to talk up the petroleum resource potential of their exploration areas. Often this is done to make investment in their company seem more attractive. Whilst the larger integrated international oil and gas companies do not need to play such games, there are times when they might exaggerate the potential of undrilled leads and prospects to the non-technical minds of political leaders in an attempt to persuade them to consider favourable treatment and regulatory actions.   Petroleum Resources Management System The petroleum industry has rules about such matters. The systematic reporting of petroleum resources has been developed progressively over nearly one hundred years.  Today, the Petroleum Resources Management System (PRMS) is highly developed, and subject to regular revision and update. It is published by the Society of Petroleum Engineers, and its Oil and Gas Reserves Committee. It has wide industry input and sponsorship from other industry organisations, such as the World Petroleum Council (WPC), and the American Association of Petroleum Geologists (AAPG), among others. The PRMS provides a consistent approach to estimating petroleum quantities, evaluating projects, and presenting results within a comprehensive classification framework.   Petroleum First of all, we need to be sure of what we are talking about.  Petroleum is defined as a naturally occurring mixture consisting of hydrocarbons in the gaseous, liquid, and or solid state. Petroleum may also contain non-hydrocarbons, common examples of which are carbon dioxide, nitrogen, hydrogen sulphide, and sulphur, and in rare cases, non-hydrocarbon content can be greater than 50%. Interestingly enough, in Papua New Guinea, although the definition of petroleum is more or less the same, the Oil and Gas Act simultaneously refers to helium alongside petroleum.  Helium was found in both the Barikewa 1 and Iehi 1 wells drilled respectively in 1958 and 1960 by Island Exploration Company and the Australasian Petroleum Company. Albeit in relatively low concentration of only about 0.1% in the discovered natural gas stream, it may one day yet have commercial value if the gas from these fields is ever produced for LNG production.   Petroleum Resources The term petroleum resources is used to encompass all quantities of petroleum both recoverable and unrecoverable naturally occurring in an accumulation on or within the Earth’s crust, discovered and undiscovered, plus those quantities already produced. Further, it includes all types of petroleum whether currently considered conventional or unconventional.   Petroleum Reserves Petroleum reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must satisfy four criteria. They must be discovered, recoverable, commercial, and remaining (as of the evaluation’s effective date) based on the development project(s) applied. Reserves are recommended as sales quantities as metered at the reference point. Where the entity also recognises quantities consumed in operations as reserves these quantities must be recorded separately. Non-hydrocarbon quantities are recognized as reserves only when sold together with hydrocarbons or volume consumed in operations associated with petroleum production. If the non-hydrocarbon is separated before sales, it is excluded from reserves. Reserves are further categorized in accordance with the range of uncertainty and should be sub-classified based on project maturity and/or characterised by development and production status. The PRMS summarises this in its Resource Classification Framework. The horizontal axis reflects the range of uncertainty of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the chance of commerciality, which is the chance that a project will be committed for development and reach commercial producing status.   Figure 5: Resources Classification Framework, after the Petroleum Resources Management System (PRMS) of the Society of Petroleum Engineers.   Proved, Possible and Probable Reserves In dealing with uncertainty of petroleum reserves, the PRMS classically uses the terms: proved, probable and possible.   Proved reserves are those quantities of petroleum that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable from known reservoirs and under defined technical and commercial conditions. If deterministic methods are used, the term “reasonable certainty” is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves, but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Possible reserves are those additional Reserves that analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high-estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Of course, to be presented as a reserve the petroleum in question has to be discovered, recoverable, commercial, and remaining to be recovered based on a scheme of development to be applied. Where petroleum accumulations fall short of these criteria, they are generally considered to be contingent resources.    Commerciality Discovered recoverable quantities of petroleum or contingent resources may be considered commercially mature, and thus attain reserves classification, if the entity claiming commerciality has demonstrated a firm intention to proceed with development. This means the entity has satisfied its internal decision criteria. This is typically the rate of return at or above the weighted average cost-of-capital or the hurdle rate. Commerciality is achieved with the entity’s commitment to the project and all of the following criteria: Evidence of a technically mature, feasible development plan. Evidence of financial appropriations either being in place or having a high likelihood of being secured to implement the project. Evidence to support a reasonable time-frame for development. A reasonable assessment that the development projects will have positive economics and meet defined investment and operating criteria A reasonable expectation that there will be a market for forecast sales quantities of the production required to justify development. There should also be similar confidence that all produced streams (e.g., oil, gas, water, CO2) can be sold, stored, re-injected, or otherwise appropriately disposed. Evidence that the necessary production and transportation facilities are available or can be made available. Evidence that legal, contractual, environmental, regulatory, and government approvals are in place or will be forthcoming, together with resolving any social and economic concerns. One might consider the current status of the Elk-Antelope gas field which is to be developed for production gas as feedstock for processing as liquefied natural gas (LNG) by the renowned international oil and gas company, TotalEnergies. In the context of the PRMS, the petroleum of the Elk-Antelope gas field is on the brink of becoming commercial, and thence considered as petroleum reserves. The PRMS nicely demonstrates the transition of contingent resources where development is pending to reserves justified for development and then approved for development. The fields currently contributing gas to the PNG LNG Project clearly have proved reserves which are either currently being produced or are to be produced.  As such fields continue to produce gas their proved reserves are systematically depleted by that production. We term production as the total cumulative quantity of petroleum that has been recovered at a given date. Proved reserves may be replenished as the operating company obtains more and more information about the petroleum accumulation it is producing and their reservoirs.  Reserves which previously had less certainty of recovery may migrate from the possible reserve category to the probable reserve category and likewise from the probable category to the proved category.  This is not a certainty, but the phenomenon of reserve creep is often realised as production continues, reservoir knowledge and understanding of its behaviour are amassed and field experience expands, but not always. There can be equally disappointing outcomes.   Figure 6:  Sub-classes of petroleum based on project maturity, after the Petroleum Resources Management System (PRMS) of the Society of Petroleum Engineers.     Plays, Leads, and Prospects Oil companies will talk of checking out a play. A play is a geological argument used to justify exploration for hydrocarbons. Critical geological ingredients may be present in an area that may encourage the notion that petroleum accumulations might have formed within the subterranean strata.  A sedimentary basin may have developed sometime in geological history within the strata of which buried organic material may have matured into oil and gas. The petroleum geologist will have ideas of possible trapping mechanisms which may have caused any generated petroleum to have accumulated in geological traps which would necessarily have to be formed before the petroleum migrated due to its buoyancy.      Geological, geophysical and geochemical are undertaken to identify potential structural trends which may provide potential traps. These are often called leads.  When such leads are examined more closely to ascertain that they meet all the criteria for formation of a petroleum accumulation, prospects may emerge which may be worthy of drilling to determine whether there might be a petroleum accumulation worthy of commercial production. Oil companies will drill their best and largest prospects with the hope of finding oil and gas. Alas, all parameters for the formation of an accumulation have to be present and with the correct timing, so often drilling is not successful. Subtleties of geological history and evolution of the geology of the area may preclude the prospect from bearing hydrocarbons. Sometimes perseverance is required as the drilling of several prospects provides more specific geological knowledge of the area, and eventually a discovery is made. There are so many cases where companies have drilled a series of well unsuccessfully, only to have a pleasant surprise eventually with a late discovery.    Figure 7: Plays, leads and prospects, after Sabrine Berkat, ALNAFT, Algeria.       Appraisal Once a discovery is made, the question everyone asks is, “How big is it?” This is a simple, but daunting question.  A typical petroleum prospect in Papua New Guinea might need to be of considerable size to justify and warrant it being drilled in the first place. Take for example, the Iagifu prospect of the Iagifu-Hedinia oil field, in production since 1992 as part of the Kutubu Project. Its pre-drill prospect structure was approximate 6 kms long by 3 kms wide, and ellipsoidal in shape covering an area of about 56.5 square kilometres.  Consider that the drill bit that first entered the oil-bearing Toro Sandstone reservoir at 2,430 metres depth in the well was just 12-1/4 inches in diameter, or only 0.076 square metres or 760 square centimetres in area. That bit probed only just over five billionth parts of the prospect, a minute portion of the prospect indeed. A discovery is nice, but it does not make a field. Sometimes there is not even a defined accumulation, if the discovery cannot be delineated or appraised by further drilling to map out the lateral extent of the accumulation across the geological structure which formed the prospect. There was an extraordinary discovery called Makas 1-X, which was drilled in the 1990s and which allegedly found an oil-bearing sandstone. The well ran into technical difficulties and had to be re-drilled, but when that new well encountered the reservoir sandstone, it was barren of oil. In this instance, appraisal refuted the supposed discovery. Appraisal seeks to probe the full extent of a newly-discovered petroleum accumulation by the drilling of more wells into the prospect. This is done to gauge whether the accumulation contains enough petroleum to be able to sustain production on a profitable commercial basis. It is an important critical stage of petroleum development. The drilling of further wells on a discovery has to be encouraged and promoted, and if necessary, government regulators need to ensure it takes place.    Figure 8: An early post-discovery depth map of the top of the oil-bearing Toro Sandstone reservoir over the Iagifu and Hedinia anticline, after Paul Lamerson, Chevron, 1988.     The operating petroleum company may not wish to spend precious financial resources on appraisal immediately. It may have other competing or urgent investments.   The Papua New Guinea legislation does not define the term appraisal of a discovery, but appraisal of a petroleum discovery is included in the rights of petroleum prospecting licensee. However, the government may direct the licensee to do such things as are thought necessary including the completion of wells, the conduct of drill stem or extended production tests for appraisal of a discovered petroleum accumulation. More specific appraisal requirements are contained either in legislation, licence conditions or production sharing agreements elsewhere.  The Papua New Guinea Oil and Gas Act does enable the declaration of what is known as a Location over the specific block within which a discovery is made, and up to eight adjoining blocks (a block is 5 minutes latitude by 5 minutes longitude, or about 81 square kilometres at the latitudes of Papua New Guinea). The declaration of a Location enables some degree of retention of the licence area by the discoverer, but also importantly triggers the ability of the Government to  require various investigations and studies as to assess the feasibility of the construction, establishment and operation of an industry for the recovery of petroleum from the location, particularly technical and economic feasibility studies relating to the recovery and transport of petroleum from the location and processing of the petroleum.   Estimating the Resources Once a petroleum accumulation has been found and appraised by the drilling of further wells which have shown that the petroleum can flow to the surface, the next big question is the size of the accumulation. Essentially, size of the accumulation it is a matter of size of the reservoir, and that in turn depends on the size of the geological structure that may have formed the trap within which the petroleum got trapped and has been found. Quite simply, the more petroleum bearing rock there is, the more petroleum will be in-place; we call this the bulk rock volume.  In simple terms, this is the area of the reservoir times its thickness, though complexities of the geological structure and its shape make this considerably more complicated.  Now, we must remember that in a conventional petroleum reservoir, the petroleum is located in the pores within the rock, a bit like water in a sponge. So, determining the porosity of the reservoir rock is a fundamental factor that has to be measured. A sample of rock can be obtained from the well and physical studies can be made of it to ascertain its porosity as a percentage of the rock, or electronic tools can be lowered into the well to measure physical properties of the rock from which its porosity may be calculated. Within the subsurface rock strata, water abounds, remnant from the time of deposition. When petroleum accumulates in a porous reservoir rock it, displaces the water, but not perfectly or completely. There is always some water left behind. Accordingly, a portion of the porosity of the rock still contains water depending on local subsurface geological condition.  Again, measurements can be made of the reservoir rock in situ by special electronic tools to ascertain what percentage of the pores is filled with water, and what percentage is filled with petroleum.  This, we call the water saturation. When petroleum flows to the surface from a reservoir, it is moving from a location of high pressure and somewhat elevated temperature to standard atmospheric conditions. Oil containing gas will shrink as it rises up the well to ambient conditions as the gas comes out of solution. There is also some shrinkage due to temperature change effects and expansion due to pressure relief.  This volume change is called the shrinkage and is expressed as the formation volume factor, the ratio of the volume of petroleum at reservoir conditions to the volume at surface conditions. It typically ranges from 1.0 to 3.0.  In the case of gas, as it flows up the well, it will expand in classic response to the decrease in pressure and temperature from subsurface reservoir conditions to surface conditions.  The gas formation volume factor is generally much lower, ranging from 0.001 to 0.01 reservoir volume per surface volume. Multiplying these factors together, in broad terms, we get: Volume of petroleum at surface = bulk rock volume x porosity x (1-water saturation)/formation volume factor      This is what we call a volumetric method, which is adequate in cases where we have some idea of rock and fluid parameters. It is generally used in early stages of appraisal of an accumulation.  Other methods are the material balance method in which the tracking of pressure changes is used to estimate remaining reserves, and decline curve analysis, which uses field production data trends to predict future output. Of course, this discussion is quite generalised, and there are many intricacies and additional dependencies.   Figure 9: Classical methods of petroleum reserve analysis after petroleum concepts on Instagram Petroleum is normally a complex mixture of many different hydrocarbons. Oil most often contains hydrocarbon gases in solution and natural gases contain liquid hydrocarbons in solution. Also, rarely are reservoirs undisturbed and quite often the very tectonic forces that created the geological structure within which the petroleum has been trapped may cause intricate faulting of that reservoir. This can often spoil the continuity of the reservoir and effectively break it up into many small pieces of reservoir some of which may not have been able to be charged with oil or gas.   This often only becomes evident when infill drilling between the discovery and appraisal wells demonstrates such discontinuities. Faults identified in the wells within the reservoir rocks indicate localised tectonic displacement and what is called compartmentalisation.  This is the case in the Kutubu oil fields which then required very careful placement of production wells to tap the oil-bearing parts of the reservoir. Sometimes water enters the petroleum bearing reservoir and flushes the hydrocarbons out of place leaving behind only a residual viscous smear of the original oil charge of the reservoir and the flushing waters.  Such was the case in the Toro sandstone reservoir of the large Mananda anticline which showed excellent signs of bearing oil, but the primary charge had been flushed away leaving only a non-recoverable residue.  In some reservoirs, the porosity of the reservoir varies laterally due to changes in the original depositional environment of the sediments, or later mineralogical or chemical changes.  The amount of water remaining in the reservoir pores can vary across a field, and hence the degree of fill of that porosity by hydrocarbons.   As one may realise, the assessment of the original oil-in-place or original gas-in-place can become quite tricky.  Then, there is one more factor that is absolutely necessary for the oil and /or gas to flow into the well bore; that is permeability.  Permeability is the ability of a porous material (such as rock) to allow fluids (either liquids or gases) or gases to flow through it. Permeability measures how easily fluids flow through the interconnected pores under pressure. High permeability allows easy flow, while low permeability restricts flow. The majority of rocks (more than 93%) have very little permeability and a small amount (2%) have fair to good permeability, the balance are considered to be poorly permeable or tight. From the 2% permeabilities range from 1 to 1000 milliDarcies (mD, the unit of permeability named after Henri Darcy).  In the Hides gas field, the reservoir permeabilities of the Toro Sandstone reservoir range from 3 to 2,000 mD with the bulk of readings being between 30 to 150 mD.  Such permeability would be said to be good. Both permeability and porosity are related and in the Hides gas field Toro reservoir, permeability broadly scales with porosity which ranges between 2% to 18%.   Recovery Factor It is good to have an accumulation full of hydrocarbons in a porous and permeable reservoir, but those hydrocarbons still need to be able to get to the surface to be able to be sold. They need to be recovered as oil and gas production. Exactly how much oil and/or gas may be recovered from a reservoir by production is not so easy to estimate.  For oil and gas to flow into a wellbore from a reservoir rock and flow to surface requires energy. The flow has to combat gravity and frictional forces to get to the surface. So quite obviously the higher the pressure of the reservoir and the less viscous the petroleum is, the better it will flow.   Measurements of reservoir pressure are therefore most important.  In a gas field, the natural gas will fill its container, the reservoir and pressure within the connected reservoir will equilibrate.  As the gas is produced, the reservoir pressure will decrease just like a balloon deflating until such time as there simply is not enough pressure to force the gas out of wellbore. That then is the technical end of production. A crude estimate of the recovery factor of a gas field may be expressed as 1 minus the reservoir pressure at abandonment divided by the initial reservoir pressure. Typical gas fields have high recovery rates of between 50% to 80%.   Figure 10: Recovery factor versus depth of gas fields outside the USA with larger than 1 trillion standard cubic feet of gas in place, after Jean Laherrère, International Energy Agency. Of course, gas fills its container and has a very low viscosity; oil is quite different. It is viscous, a liquid and hence moves much more slowly.  It does not fill its container as gas does. When a well penetrates an oil-bearing reservoir, the oil has to flow toward the borehole in response to a decrease in pressure caused by the well’s penetration into the reservoir.  As the pressure differential between the wellbore and reservoir decreases with time, the oil becomes more and more sluggish.  Lighter density oils move easier, but heavier density oils have a hard time. The amount of gas dissolved in the oil very much affects the ability of the oil to flow out of the well because as the pressure is relieved, the gas bubbles out of solution (just like opening a Coca Cola bottle) frothing up the oil and making the oil flow lighter and easier to ascend the well.  The amount of gas contained per barrel of oil in solution is known as the gas-oil ratio.  In the case of the Kutubu fields, the oil was very gassy from the beginning, and so recovery of the oil was much easier.  Indeed, there was so much gas produced with the oil that for many years the gas was reinjected back into the reservoir to help push the oil to surface. In this way, it was also effectively conserved until it too could be produced in the current PNG LNG Project.  Some oil-bearing reservoirs are linked in the subsurface to active aquifers which provide additional energy to help maintain the reservoir pressure for a longer period of time.  Petroleum engineers and production geologists quite often devise water injection schemes to aid oil recovery in which massive amounts of water are pumped into the water lying below the oil to help it flow to the production wells. This is called water flooding. Whilst the extent of gas recovery from a reservoir is more fundamentally connected to the change of reservoir pressure, the extent of oil recovery is not so readily estimated. Elaborate reservoir models may be built describing the reservoir rock, reservoir fluids and their parameters to create simulations of flow through an array of production wells.  These simulations can be correlated to actual flow of wells when tested and an overall assessment of likely recovery scenarios made. Typical oil recovery rates are between 5% to 50% of the original oil-in-place, with an average often cited of around 30% to 35%. Secondary recovery techniques like water flooding and gas injection enhance recovery to between 30 to 40%. Enhanced oil recovery (EOR) techniques may significantly increase recovery by the injection of heat, gases, chemical to reduce viscosity and improve flow, but this comes at a cost.      Figure 11: Recovery factor of 800 oil fields outside the USA, after Jean Laherrère, International Energy Agency   Ultimate Recovery As one produces a field, be it an oil field or a gas field, the resources that were estimated to be in place at the beginning of production are steadily depleted. The extent of the recoverable reserves is reduced by every additional amount of production, so the reserves of a field decline. Those reserves that have been recovered and those that may yet be potentially recovered are referred to as the estimated ultimate recoverable reserves of the field. This is the ultimate measure of the total potential commercial output of a field. To talk of the reserves of a particular petroleum province and its fields one can only project into the future as those resources that were once reserves and have been produced are no longer such. The estimates of reserves are estimates of the volumes of oil and gas that may be commercially recovered henceforth. A common measure of the utility of such reserves is the reserve-to-production ratio (R/P ratio). This estimates how many years the oil or gas will last at current production rates. It is calculated by dividing remaining proven reserves by the annual production rate. A higher R/P ratio indicates more years of supply remaining. If one looks at the Statistical Review of Global Energy, the last edition that examines the R/P ratio was in 2020 providing statistics up to the start of Covid.  Oddly, after that BP and then the new owners of this great and useful report found it necessary to omit the listings of oil and gas reserves and with that, the comparative R/P ratios, perhaps to mollify the notion that a world in energy transition would still be producing oil and gas for decades to come.  Of course, circumstances change as we have seen in the dramatic actions of some nations in the first quarter of 2026.  The picture is clear; a select few countries dominate oil production now and in the longer term. Their ability to produce oil into the foreseeable will depend on their access to markets, which if denied may render their reserves to be purely technical.   Country Proved Reserves (Billion Barrels of Oil) R/P Ratio (Years) Canada 169.7 82.3 Iran 155 120.6 Iraq 145 83.1 Kuwait 101.5 83.1 Russia 107 25.5 Saudi Arabia 297.6 68.9 USA 68.9 11.1 Venezuela 303.8 906.7 Total World 1,733.9 49.9 Figure 12:  Reserve-to-production ratios of countries with more than one billion barrels of proved reserves and the USA as at pre-Covid pandemic in 2019 after Statistical Review of Global Energy. A similar story can be told for natural gas reserves. It is with respect to natural gas that Papua New Guinea earned a row in the statistics of the Statistical Review of Global Energy, having an assessed 0.2 trillion cubic metres of gas as proven reserves and an R/P ratio of 14.2 years.  Papua New Guinea has been producing oil and gas since 1991 when the Kutubu Project produced its initial oil as feedstock for the Project refinery and the Hides Project produced its initial gas as feedstock for the Porgera mine power plant. In 1992, full scale oil production began at Kutubu and in 2014 large scale gas production at Hides for the PNG LNG Project commenced. Papua New Guinea’s discovered oil and gas fields are listed below together with their estimated ultimate recoverable resources and reserves, which includes production to date and remaining resources and reserves. Field Name(s) Year of Discovery Current Licence Current Operator Estimated Ultimate Recoverable Oil Resources and Reserves Estimated Ultimate Recoverable Gas Resources and Reserves         Million barrels  2C & 2P (incl. condensates & LPGs) Billion cubic feet 2C & 2P Barikewa 1958 PRL 49 Kumul Petroleum   439 Bwata 1960 PRL 39 ExxonMobil   68 Cobra & Iehi 1960 PRL 14 Santos   72 Uramu 1968 PRL 60 Kumul Petroleum   92 Pasca 1968 PPL 328 Twinza 90 464 Juha 1983 PDL 9 ExxonMobil 29 578 Kutubu 1986 PDL 2 Santos 337 1733 Hides 1987 PDL 1 ExxonMobil 159 6938 Pandora 1988 PRL 38 Kumul Petroleum   644 Agogo 1989 PDL 2 Santos 59 541 Angore 1990 PDL 8 ExxonMobil 13 1079 Elevala & Ketu 1990 PRL 21 TWL Energy 40 640 P'nyang 1990 PRL 3 ExxonMobil 78 4600 SE Gobe 1991 PDL 3 Santos 46 156 Gobe Main 1993 PDL 4 Santos 31 159 Paua 1995 PPL 378 Giri Energy 17   Moran 1996 PDL 2&5 Santos 20 344 Stanley 1999 PDL 10 TWL Energy 12 399 Kimu 1999 PRL 48 Kumul Petroleum   525 Triceratops 2005 PRL 39 ExxonMobil 2 30 Douglas 2006 PRL 40 TWL Energy 30 500 Pukpuk 2006 PRL 40 TWL Energy 0 365 Elk-Antelope 2006 PRL 15 TotalEnergies 64 6200 FlInders & Hagana 2006 PRL 41 Santos   1100 Ubuntu 2011 PRL 28 TWL Energy 4 100 Muruk 2016 PPL 402 Santos   845    Summations 1031 28611 The summations are pseudo-summations only, not statistical aggregations and should be used as a guide only Figure 13: A list of oil and gas field discoveries in Papua New Guinea and their estimated ultimate recoverable resources and reserves (2C and 2P respectively) after David Manau, Secretary, Department of Petroleum and Energy (now Managing Director, National Petroleum Authority) modified and amended by the author from public information. The extent of the future discovery of Papua New Guinea’s petroleum resources will depend entirely on investment in exploration and the necessary drilling of valid prospects.  In turn, the extent of reserves will depend on investment in development where production of those reserves may be assessed to be commercial.  Without such further investment, we can only produce those resources and reserves that are remaining until they are depleted to the extent that we can, given considerable infrastructure limitations.   Only successful exploration including the vital drilling of exploration wells will allow the above table to be augmented with Papua New Guinea’s yet to be found petroleum resources and reserves.   Word = 6,927    

With urban migration putting increased pressure on housing in centres such as Port Moresby, Lae, Mt Hagen and Kokopo, Nasfund has reintroduced its virtual member education sessions this August. The move underscores the Fund’s commitment to digital innovation while responding proactively to members’ concerns. Running throughout the month, the free online sessions focus specifically on the Housing Advance product. The initiative has already generated strong engagement, with recent campaign data showing that 63% of participants are requesting longer discussions and additional resources. Nasfund Chief Executive Officer Rajeev Sharma, who also serves as president of the Association of Superannuation Funds of Papua New Guinea (ASFPNG), said the Fund’s digital innovation must be supported by practical and modernised legislation. “The feedback we are getting from these virtual sessions directly mirrors the concerns raised by members right across the industry,” Sharma said. “We strongly support ASFPNG’s call for the Government to prioritise these long-standing reforms. The industry stands ready to work collaboratively with the Government to implement meaningful changes that improve member outcomes.” While the digital platform helps members understand eligibility requirements and documentation, the sessions have also highlighted widespread frustration with the current laws governing superannuation in PNG. Members frequently question why they are limited to two advances and why a second advance is strictly capped at the amount of the first. “That is why we conduct these sessions, not only online but also as part of our awareness efforts for members. Nasfund is an authorised superannuation fund governed by the Superannuation Act 2002,” Sharma said. Nasfund Head of Marketing and Stakeholder Engagement Melanie Lavaki said leveraging technology was broadening the Fund’s reach and strengthening its efforts to improve superannuation literacy. “Reintroducing these virtual sessions has noticeably increased awareness across all our communication channels,” Lavaki said. “Our branches remain crucial to how we operate, but these online sessions complement our physical engagements perfectly.” Members interested in learning more about the Housing Advance product are encouraged to participate in the virtual sessions and engage with the member service team for ongoing guidance.

Gold sponsor highlights on-premises AI, resilient power and emerging technologies as Papua New Guinea advances its digital economy THEODIST Limited has reinforced its growing role in Papua New Guinea’s information and communications technology sector after showcasing enterprise ICT, artificial intelligence, mobility, digital media and power continuity solutions at the Digital Transformation Summit 2026 (DTS26) in Port Moresby. Organised by the PNG Department of Information and Communications Technology, DTS26 brought together government leaders, Pacific representatives, private-sector organisations, development partners, technology specialists, educators and emerging innovators. The summit focused on building Papua New Guinea’s digital public ecosystem through trust, infrastructure, innovation and inclusion, with discussions covering artificial intelligence, cybersecurity, digital identity, connectivity, digital skills and digital government. As a Gold Sponsor of DTS26 and Major Sponsor of the eGames, THEODIST used the national platform to demonstrate how international technology can be applied to practical operating challenges in Papua New Guinea when supported by local advice, implementation and after-sales capability. The company said its exhibition booth attracted strong interest from government agencies, business leaders, ICT professionals and technology enthusiasts seeking solutions that could improve productivity, strengthen resilience and support secure digital adoption. A major feature of the display was the MSI EdgeXpert MS-C931, a compact AI supercomputer based on the NVIDIA DGX Spark platform and powered by the NVIDIA GB10 Grace Blackwell Superchip. The system provides up to 1 petaFLOP of FP4 AI performance and 128 GB of unified memory, allowing suitable AI models and workloads to be developed and run locally. For organisations handling sensitive information or requiring fast response times, local AI computing can provide greater control over selected data and workloads, reduce latency and maintain capability where reliance on external connectivity may be a concern. THEODIST positioned the technology as a practical complement to cloud computing, allowing organisations to choose where each workload should operate according to its security, scale and performance requirements. THEODIST Chief Executive Officer Kumar Baliah said the level of engagement at the summit showed that Papua New Guinean organisations were increasingly looking beyond individual products and seeking technology partners capable of advising, implementing and supporting complete solutions. “Digital transformation is not about introducing technology for its own sake. It is about applying the right technology to improve productivity, protect information, strengthen service delivery and create new opportunities,” Mr Baliah said. “PNG organisations need access to world-class solutions, but they also need local expertise, dependable support and an understanding of the operating conditions in which those solutions will be used. THEODIST’s role is to connect global technology with local capability and help customers adopt it with confidence.” THEODIST Limited | Media Article for Publication The DTS26 display also featured the Hypershell X Ultra wearable exoskeleton, demonstrating the potential of assisted mobility technology for demanding field environments. Digital content creation and field operations were represented through DJI’s Osmo Pocket 4 Creator Combo and portable power solutions, including the DJI Power 1000. THEODIST also showcased the BLUETTI AC300 modular power system, which provides 3,000W AC output and can be paired with compatible expansion batteries to create scalable backup and off-grid power capacity for businesses, institutions and remote operations. These technologies were presented within the context of Papua New Guinea’s practical needs, including operations in remote locations, continuity during power interruptions, mobile fieldwork and the growing requirement for organisations to produce and communicate digital content. Beyond the exhibition, THEODIST supported the development of emerging digital talent through its sponsorship of the DTS26 eGames. Around 20 teams participated in the national competition, which formed part of the summit’s broader programme to encourage young people to engage positively with technology, teamwork, problem-solving and digital careers. At the DTS26 Gala Dinner, THEODIST presented prizes to the leading eGames teams: Shadow Dwellers, Checkmate and Rising Suns. The company said the competition demonstrated the discipline, collaboration and technical confidence developing within Papua New Guinea’s young digital community. Mr Baliah said supporting digital talent was an important part of building the country’s long-term capability. “The future of digital transformation will ultimately depend on people. Infrastructure and equipment are essential, but sustainable progress requires skilled, curious and adaptable Papua New Guineans who can use technology to solve real problems,” he said. “By supporting the summit and the eGames, THEODIST is investing not only in technology, but also in the partnerships, skills and confidence needed to build a stronger digital economy.” Established in 1968, THEODIST has expanded from its traditional office products base into a broader business solutions company serving corporate, government, education and retail customers. Its growing ICT portfolio includes enterprise technology, AI-enabled computing, business continuity, managed solutions and products from international technology brands, supported by local service teams. THEODIST thanked the PNG Department of Information and Communications Technology, ICT Minister Hon. Robert Naguri, Secretary Steven Matainaho, the DTS26 organising committee, technology partners and delegates who engaged with the company during the summit. With DTS26 now concluded, the company said its focus would turn to converting the discussions and new relationships created at the summit into practical projects that help organisations across Papua New Guinea innovate, transform and grow.