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Acting Minister for Information and Communications Technology Peter Tsiamalili Jr. formally closed a week-long programme on international cyber law and cybercrime cooperation, calling it a pivotal step in Papua New Guinea’s digital development pathway. The workshop, held at APEC Haus from 9 to 13 February, brought together government agencies, international experts, and partners to strengthen PNG’s national capability in cyberspace. In his closing remarks, Minister Tsiamalili emphasised that protecting essential systems, maintaining trust, and responding credibly to cyber incidents is now “mandatory, not optional” for the country. “The Government is very clear on what it wants to achieve,” he said, reflecting on PNG’s realignment of priorities since its 50th anniversary last year. He noted that the ICT sector has become an integral part of every government function and operation. Minister Tsiamalili highlighted PNG’s recent international commitments, including Parliament’s ratification of the Budapest Convention on Cybercrime in November 2025. He noted that the country is now set to deposit its instrument of accession. PNG also signed the Hanoi Convention, informally known as the United Nations Convention Against Cybercrime, in October 2025 in Hanoi, Viet Nam, and has taken deliberate steps to align national policies with trusted international frameworks. “These actions reflect PNG’s intent to build a lawful, credible, and cooperative national posture, supported by real institutional capability,” Minister Tsiamalili said. He underscored PNG’s regional leadership, citing the 2023 Lagatoi Declaration as evidence of Pacific Island Forum countries’ shared understanding that cooperation is essential to protecting citizens and growing digital economies. Accession to the Budapest Convention, he added, will strengthen collaboration with State Parties in the Pacific and globally on lawful data requests, timely assistance, and coordinated responses to cybercrime. During the week-long programme, participants completed the course International Law Applicable in Cyberspace, which focused on implementing the Budapest Convention. International faculty from Cyber Law International, including Ms Liis Vihul, Professor Marko Milanovic, and Mr Alexander Seger, guided PNG officials through legal principles, enforcement realities, and cross-border cooperation. Closing the programme, Minister Tsiamalili stressed immediate follow-through. “The task now is execution: coordinated institutions, clear mandates, lawful powers, safeguards that protect rights, and trained officers who can act quickly and correctly. Let us translate this week’s learning into a national work programme with clear responsibilities and timelines.” He said PNG’s accession to the Budapest and Hanoi Conventions marks a major national step, aligning institutions with trusted international standards for tracking cybercrime and enabling lawful cooperation on electronic evidence. The programme was co-organised by the Government of Papua New Guinea through NICTA and facilitated by the Australian Government through Australian AID.

 The Autonomous Bougainville Government (ABG) has clarified its position on Bougainville Copper Limited (BCL) and the redevelopment of the Panguna mine, following questions over recent partnering arrangements. The ABG confirmed that Bougainville now holds a 72.9 per cent shareholding in BCL, split evenly between the ABG and Bougainville Minerals Limited, making it the controlling majority shareholder. Under corporate law, this status allows the ABG to determine the strategic direction of the company in the best interests of the people of Bougainville. “The ABG operates in two distinct capacities — as regulator under the Bougainville Mining Act and as majority shareholder in BCL,” President Ishmael Toroama said. “All developments involving BCL, CMOC, and Lloyds Metals and Energy Limited are occurring strictly at the shareholder level, with no regulatory breaches or issues under the Mining Act.” BCL retains lawful control of Exploration Licence EL01 over Panguna and remains responsible for implementing its approved work programme. This includes land access and compensation agreements, landowner identification, social mapping, geological and engineering studies, environmental baseline studies, and other statutory obligations. While BCL currently lacks the technical and financial capacity to advance EL01 activities independently, a previous proposal to introduce CMOC as a partner — which would have diluted Bougainville’s shareholding by around 20 per cent — was rejected by the ABG. Instead, the Government has endorsed Lloyds Metals and Energy Limited (LMEL) as a partner to provide the necessary funding and technical expertise to progress exploration under EL01. President Toroama clarified that recently referenced timelines for Panguna relate solely to Pre-Feasibility and Feasibility Study activities under the EL01 licence and are not production timelines. The ABG remains committed to a lawful, transparent, and orderly development process that delivers tangible benefits to the people of Bougainville. ABG Launches Stakeholder Awareness Program Following the statement, the ABG initiated stakeholder awareness meetings in Arawa this week. The programme, led by the Department of Mining & Petroleum in collaboration with the Department of Community Government, aims to ensure that communities, local government authorities, and landowners are fully informed about developments relating to BCL, LMEL, and the Panguna EL01 project. On 17 February, ABG officials met with government authorities from the Panguna and Kieta Districts, including ward members from the Ioro Community Government, to brief public servants on the latest developments. Officials also held a session with Panguna landowners to provide updates and discuss landowner priorities, reaffirming the ABG’s commitment to dialogue, transparency, and collaboration. Stakeholder engagement will continue as the ABG seeks to maintain unity, clarity, and informed participation in decisions regarding the Panguna project. The Government encourages all parties to rely on official communications for accurate information.  

 Kumul Petroleum Holdings Limited, Hevehe Petroleum Limited and Twinza Oil (PNG) Limited have signed a Memorandum of Understanding (MoU) to jointly investigate gas aggregation opportunities in the Gulf of Papua. The agreement provides a framework for the parties to undertake joint studies and evaluate the technical and commercial feasibility of aggregating gas from discovered or prospective assets within the broader Gulf of Papua area for domestic use and/or export through shared infrastructure. Luke Liria, acting managing director of Kumul Petroleum, said the company welcomed the partnership as part of its mandate as the national petroleum and energy company. “KPHL, as the national petroleum and energy company, looks forward to partnering with MRDC and Twinza to explore pathways that could accelerate the development of Papua New Guinea’s offshore gas resources and contribute to the national economy,” Liria said. Augustine S. Mano, managing director and chief executive officer of Mineral Resources Development Company (MRDC), described the MoU as an important step for MRDC and Hevehe Petroleum. “Landowners and provincial governments hold 50 per cent of the Pasca A Project through Hevehe, and this gives real value to their participation. By working with Kumul Petroleum and Twinza, we can look at ways to develop gas in the Gulf of Papua more efficiently and at lower cost. This will lead to better returns for our landowners and communities. We are committed to using our experience to support this partnership and deliver long-term benefits for our people,” Mano said. Stephen Quantrill, executive chairman of Twinza, said the MoU marked a significant step towards unlocking offshore oil and gas potential in the Gulf of Papua. “By assessing the aggregation of resources from multiple discovered and prospective fields, we will evaluate shared infrastructure to enhance commercial viability for both domestic use and export. This collaboration enables us to jointly pursue strategic growth, ensuring we create a scalable, efficient energy platform for the benefit of partners and for the people of PNG,” Quantrill said. Twinza is the operator of the Pasca Project, PNG’s first offshore oil and gas development, and is partnering with MRDC and Kumul Petroleum under the new agreement to examine options for coordinated development in the Gulf.  

The Sepik Development Project (SDP) is a nation-building initiative in Papua New Guinea, delivering transformative infrastructure, renewable power, and essential services to remote communities while responsibly developing one of the world’s largest gold and copper deposits. “Utilising world-leading engineering and renewable-powered design, the project is committed to protecting the Sepik River ecosystem and ensuring the safety of its communities,” said a Frieda River Limited spokesperson. Designed as one of the lowest-emission mining projects globally, the SDP supports Papua New Guinea’s commitment to energy transition and sustainable resource development. The mine will be powered by a hydroelectric dam, producing a surplus of 270 MW of electricity. This power will connect to the national grid, supplying industries and communities in the northern border frontier with clean, reliable energy, while contributing to the reduction of PNG’s long-term carbon emissions. The dam design, which continues to be strengthened and refined, incorporates world-class tailings and waste management technology to effectively mitigate risks to the Sepik River and surrounding ecosystem. It has been engineered to withstand high rainfall and seismic activity, with an embankment and spillway designed to safely accommodate extreme water flows and potential earthquake events. Water quality will be managed through advanced waste and water-management techniques, including underwater tailings storage and active treatment of open-pit water. The project’s design is informed by one of PNG’s most extensive environmental data programmes, supported by a decade of baseline studies and biodiversity surveys. Scientific modelling indicates that impacts on downstream water quality and marine life are expected to be minimal, with significant safeguards in place to protect surrounding and downstream communities. The facility is designed to store water and permanently contain process tailings and mine waste rock. Ongoing water quality monitoring will be conducted at two checkpoints during wastewater discharge activities to ensure the Sepik River and surrounding environment remain protected. “The safety of the Sepik and its communities is a key priority for the project, guided by four principles: technically appropriate, environmentally safe, socially responsible, and financially profitable,” the spokesperson added. “The Sepik Development Project is committed to genuine, inclusive engagement with communities, ensuring local voices shape how the project is planned and delivered. We believe this nation-building initiative should deliver substantial economic and social benefits to Sepik communities and PNG more broadly. We are actively listening to and working with our stakeholders to ensure this outcome.” The spokesperson also noted, “We will continue to engage fully and openly with stakeholders through our annual community engagement programmes within the project’s infrastructure and riverine footprint corridor. We welcome questions, feedback, and guidance from communities as we work to deliver a project that brings tangible benefits to landowners, local communities, and PNG as a whole.” Frieda River Limited is a significant subsidiary of the PanAust Limited Group. In addition to its pre-development opportunities in Papua New Guinea, PanAust Limited owns Phu Bia Mining — an award-winning dual operation in Laos — and has development projects in Chile. An Australian-incorporated company, PanAust is owned by Guangdong Rising H.K. (Holding) Limited, a wholly owned subsidiary of Guangdong Rising Holding Group Co., Ltd. (GDRH), a Chinese state-owned company regulated under the State-owned Assets Supervision and Administration Commission of the People’s Government of Guangdong Province.

The Autonomous Bougainville Government (ABG), through the Bougainville Agriculture Commodities Regulatory Authority (BACRA), has issued cocoa export licenses to six companies as it strengthens regulatory control over the sector and reports record production in 2025. The first three licenses were issued in October 2025 to Sankamap, Elliven and Bougainville Organic Export Company. On Friday, three additional licenses were granted to Coconut Products Ltd., AGMARK and PNG Pacific Capital Ltd., marking what officials described as Bougainville’s growing control over its cocoa industry. The issuance of licenses follows the passage of the Bougainville Agriculture Commodities Regulatory Act 2020 and the formal establishment of BACRA to regulate the agriculture and commodities sector in Bougainville. Under the regulations, the BACRA Advisory Council facilitates the screening and approval of license applications. Previously, cocoa export licenses were issued by the PNG Cocoa Board. Those functions have since been transferred to the ABG Department of Primary Industry and are now being operationalized by BACRA. ABG Minister for Primary Industry Clarence Dency said the transition represents a significant shift in the ownership and governance of one of Bougainville’s most important cash crops. “For the first time, Bougainville is fully in control of its cocoa export system. This means that 100 percent of cocoa export levies are now paid directly to the ABG through BACRA, ensuring that revenue generated from our cocoa industry stays in Bougainville and benefits our people,” Dency said. Secretary for the Department of Primary Industry Kenneth Dovaro said revenue collected through BACRA will be reinvested to strengthen the cocoa industry. “The funds generated will be used to build industry capacity through research and development, extension services, compliance monitoring and effective administration of the sector,” Dovaro said. He added that the establishment of BACRA will significantly improve data collection and planning. “For the first time, we are able to systematically collect accurate data on cocoa production across Bougainville. This will greatly improve future planning and policy decisions for the industry,” he said. Bougainville has maintained its position as the country’s leading cocoa producer in recent years, with production in 2025 reaching approximately 23,500 metric tons. “This is a historic high production level and very significant to the national and local economy, as this is valued at over K750 million from our estimates,” Dovaro said. “We estimate that about 80 percent, or K600 million, of the total revenue went directly to farmers,” he added. Under the new licensing arrangements, all cocoa exporters operating in Bougainville will be fully accountable to BACRA, including compliance with license conditions, monitoring requirements and quality standards. Officials said these requirements are expected to flow through the supply chain to farmers. The Department of Primary Industry will also conduct regionwide awareness programs targeting cocoa farmers to promote quality production, proper registration of fermentaries and compliance with industry standards. Dency said the measures are aimed at protecting and maintaining Bougainville’s reputation for high-quality cocoa while ensuring the long-term sustainability of the industry.

The Asian Development Bank (ADB) has appointed Takafumi Kadono as its new country director for Papua New Guinea, with responsibility for leading the bank’s resident mission in Port Moresby and overseeing its development engagement in the country. Kadono assumed office on January 13 and will lead the formulation and implementation of ADB’s next country partnership strategy for Papua New Guinea, guiding support across infrastructure, social services and private sector development. In a statement, Kadono said ADB would continue to work with the Papua New Guinea government to strengthen economic growth and social development through investments in transport and energy, expanded access to health and education services, and measures to improve private sector competitiveness. He also said the bank would work closely with development partners to enhance the inclusivity and resilience of the country’s financial and health systems. ADB is one of Papua New Guinea’s largest financing partners for infrastructure, particularly in the transport and energy sectors. The bank also supports technical and vocational education and training programmes, co-financed by the Australian government, aimed at improving workforce skills and alignment with industry needs. In the health sector, ADB assistance includes policy reforms, investments in health systems and measures to strengthen public financial management. A Japanese national, Kadono brings more than 26 years of international development experience with ADB and the World Bank Group. Prior to his appointment in Papua New Guinea, he served as ADB’s country director for Sri Lanka. Founded in 1966, ADB is a multilateral development bank owned by 69 members, including 50 from Asia and the Pacific. It focuses on promoting inclusive, resilient and sustainable growth through financing, technical assistance and partnerships across the region.

The Mineral Resources Development Company (MRDC) participated in the Ministry of International Trade and Investment Stakeholders High-Level Planning Workshop in Lae, Morobe Province on 16 February 2026. Deputy CEO and Chief Investment Officer John Tuaim presented MRDC’s vision to transform the East New Britain township of Kokopo into the regional tourist hub of the Pacific under the Kokopo Tourism Economic Zone (K-TEZ) Initiative. The K–TEZ initiative proposes a comprehensive infrastructure uplift program, including the construction of multiple internationally branded hotels and resorts, development of marine facilities, and supporting tourism infrastructure, with an estimated total investment exceeding US$4 billion. The infrastructure plan includes the development of Tokua Airport as an international gateway, road upgrades linking Kokopo, Rabaul, Pomio, and all tourism precincts, development of wharf, marina, and cruise ship terminal facilities, upgrades to water, power, sewerage, sanitation, and communications facilities, and further strengthening of digital connectivity and tourism safety infrastructure. The master plan envisions the construction of approximately 4,500 hotel and resort rooms across 22 properties, alongside marine and diving facilities, a precinct hub for cultural tourism and heritage, and the development of a PGA-standard 36-hole golf course. “What we are proposing under the Kokopo Tourism Economic Zone Initiative is more than a tourism proposal; it is a foreign exchange engine, a jobs and skills development engine, a domestic industrial stimulus, and a diversification strategy for PNG,” Tuaim said. He noted that tourism is one of the most powerful and proven economic multipliers available to island economies like PNG. Globally, tourism contributes approximately 10% of GDP, supports one in ten jobs, and remains one of the fastest-growing service export sectors. He said Kokopo was the ideal platform for this initiative because of its proximity to Australia, the Pacific, and Southeast Asia; its active volcanoes and geothermal attractions; World War II sites; world-class marine and diving ecosystems; strong cultural heritage; and a stable provincial government environment. MRDC has commenced exploratory discussions with the East New Britain Provincial Government, customary landowners, community leaders, and other key stakeholders to ensure that the Kokopo Tourism Economic Zone is developed through inclusive partnerships and aligned provincial planning. He said Kokopo is geographically positioned to become PNG’s tourism gateway, a domestic aviation hub, and a model province for diversified growth. “If we are to build a tourism economic zone anywhere in PNG, Kokopo is the logical starting point,” Tuaim said. He added that under the plan, the K–TEZ is expected to attract 600,000 visitors annually, delivering US$1.2 billion per year. It is expected to create 10,000 jobs directly, another 25,000 jobs indirectly, strengthen the balance of payments and foreign exchange liquidity, and contribute to Kina stability. The initiative is projected to contribute 3–5% growth to the national GDP.

 From First Oil and Gas to LNG By Michael McWalter EDITOR’S NOTE: Michael McWalter, former Director, Petroleum Division and Adviser to the Government of Papua New Guinea, and erstwhile petroleum adviser to the governments of Ghana, Liberia, Cambodia, São Tomé, and South Sudan, recalls the foundations of petroleum resource development in Papua New Guinea, and continues his story of oil and gas exploration and production in independent Papua New Guinea. Michael McWalter is a certified petroleum geologist and technical specialist in upstream petroleum industry regulation, administration and institutional development. Introduction In my last article titled “Decades of Exploration to First Oil and Gas Production,” I told the story of the early days of petroleum exploration in the new nation of Papua New Guinea up to the days of first oil and gas production in the early 1990s. Gas was first produced and sold from the Hides gas field by BP and Oil Search in December 1991, and crude oil was first produced and sold from the Kutubu fields by Chevron and their joint venture partners in June 1992. The discovery of crude oil and natural gas at Iagifu and Hides respectively in 1986 and 1987 in significantly large accumulations worthy of commercial production sparked an exploration boom in subsequent years. Papua New Guinea became a vogue place for oilmen to be. In the 20 years or so after these discoveries, Port Moresby was home to oil and gas companies large and small that needed to be in this opening frontier of exploration; such is the herd mentality of oilmen. Together they spent a staggering 3 billion kina, which amounted to some US$2 billion at the exchange rates of those days, or about US$4.1 billion in today’s money. That effort involved the drilling of some 150 wells and the conduct of some 108 seismic surveys that eventually led to the discovery of moveable hydrocarbons in 61 wells and the location of 20 new petroleum accumulation fields, though many of these contained natural gas rather than oil. I now continue the story. However, it is an immense tale, so I shall just delve into it here and there to show where the petroleum industry has taken us at the time of our 50th anniversary of independence. And I apologise if at times my tale is anecdotal or lacking. Gobe and Moran Oil Fields Along the frontal trend of anticlines in the Papua New Guinea fold and thrust belt, wells drilled on the Gobe and Moran structures found additional pools of oil, in lesser quantities than the accumulations of the Kutubu fields, but still enough to warrant development. Almost every anticline was drilled along the frontal trend, even to the point of one supposed anticline turning out upon drilling to be a syncline rather than an anticline, and thus unable to trap any fluids in the subsurface. The Moran field north-west of Kutubu was estimated to hold about 113 million barrels of recoverable oil, whilst the Gobe field was estimated to contain about 83 million barrels of recoverable reserves. Both of these fields had structural complexities due to faults that compartmentalised the accumulation of oil within the reservoirs. Figure 1: A geological section through the Moran anticline showing Moran 1X and 2 wells penetrating the tightly folded and faulted structure   This isolation of separate pools of oil also led to some considerable rivalry between adjacent petroleum licensees, who sought to exert their prowess one over the other by naming the parts of the fields in their licences differently. Hence, we had supposed field names like South East Gobe, Gobe Main, Moran Central and North West Moran. With these fields awkwardly extending across licence boundaries, both co-ordinated development and unitised development arrangements had to be negotiated between the different licence joint venture groups. This was not always easy due to often intense corporate rivalries and differing economic and commercial positions. Figure 2: A tectonic map of New Guinea showing the Papuan Thrust and Fold Belt (PTFB) on the edge of the Australian tectonic plate. The blue star marks the location of the Hides gas field. After Cloos et al 2005.     The development of these fields ensued with different production arrangements. The Moran field depended on the use of the Kutubu Central Production Facility, to which flowlines from Moran to Kutubu were installed. Meantime, the Gobe field had a separate production facility installed (the Gobe Production Facility) and a short project-specific spur pipeline. Both of these fields used the Kutubu Export trunk oil pipeline and its integral offshore Kumul Marine Terminal for transmission and dispatch of crude oil for export. This entailed the negotiation of tariffs for the use of the various Kutubu facilities, which added further complexity to the commercial arrangements for field development. However, such arrangements did serve to optimise the use of existing field processing facilities, storage and transportation systems, and obviated the unnecessary and redundant duplication of petroleum infrastructure. In the case of the use of the Kutubu Export Pipeline by the producers of the Moran Joint Venture and Gobe Joint Venture, some companies were also parties to the Kutubu Joint Venture, whilst others were not. Beguiling arguments for high tariffs were made by those members of the Kutubu Joint Venture that were not involved in these new field developments, while conversely equally beguiling arguments were made for low tariffs by those members of the Moran and Gobe Joint Ventures that were not involved in the Kutubu Joint Venture. Those involved in the new field developments as well as the Kutubu project were quite mute in their tariff arguments. The threat of impending ministerial regulation, as was then permitted by the Petroleum Act, rapidly crystallised the thinking of the various licence ventures, and those commercially adamant arguments rapidly dissolved into a commercial and fair resolution of the tariffs!   Oil Field Production Both Gobe and Moran oil fields commenced production in 1998, some six years after the Kutubu field. Gobe reached peak production in 1999 at an annualised rate of 34,278 barrels of oil per day (bopd) and declined thereafter, whilst Moran only reached peak production in 2007 at an annualised rate of 21,503 bopd. The two fields contributed to supporting Papua New Guinea’s aggregate oil production as that at the Kutubu fields inexorably declined as reservoir energy was depleted. Figure 3:  Oil production history 1991 to 2022 after the Dept of Petroleum and Energy at 16th PNG Mining and Petroleum Investment Conference and Exhibition, Sydney, Australia, 2022   The development of the Kutubu field has, in retrospect, been a great success, with oil production continuing to this day, albeit much reduced in volume from its high production rate of its halcyon days when it almost reached 150,000 barrels of oil per day, plus production of the field’s associated gas. The Kutubu development was launched on the basis of recoverable oil reserves of just 164.8 million barrels, but as of 31 December 2019, it had produced 319.8 million barrels of oil. Based on an estimated original-oil-in-place volume of 556.2 million barrels, this suggests that the original projection of just 29% recovery has eventuated in as much as 57.5% recovery by the end of 2019. With production still taking place at about 3,000 barrels of oil per day, the Kutubu field is clearly reaching its last days. It does this in considerable glory as it reaches 60% recovery of its original oil-in-place, quite an extraordinary recovery factor. Admittedly, associated gas obtained from the field separators was originally re-injected into the field at the gas/water interface as a semi-miscible flood so as to enhance oil recovery, but even by the standards of such secondary recovery techniques, this level of oil recovery has been quite remarkable. Of course, a large uncertainty always remains in the petroleum geology, insofar as we do not have precisely mapped subterranean field limits on account of it not being possible to obtain clear seismic imaging of the reservoirs. We therefore cannot rule out the possibility that oil is being extracted from an original pool that may have a geometric volume and areal extent somewhat different from that originally conjectured, which was based solely on well penetrations and geological mapping. Figure 4: The Kutubu Oil Fields structural configuration. Red is gas overlying oil in green. The grid lines are five minutes apart by latitude and longitude. After the Scheme Booklet: Merger of Oil Search and Santos 2021.   Whilst the Kutubu fields have been a great success, both Moran and Gobe fields have had a chequered development history with various problems of one kind or another. The development of the Gobe fields started with feuding over operatorship between the Chevron-led joint venture and the Barracuda-led venture. Barracuda, a subsidiary of Mount Isa Mines Ltd, had acquired the small independent company Command Petroleum, which had bravely drilled the South East Gobe-1 discovery well as operator of Petroleum Prospecting Licence No. 56. Chevron’s prowess won out, and they retained operatorship over the Gobe field development and subsequent production. Intractable problems with customary landowner identification of the people of the Gobe area have persisted through development and production. The land of the Gobe Mountains was gazed upon by both people from the north and the south and only sparsely used for hunting and gathering and ancestral rights. The land was hotly contested, and ownership was very difficult to determine outright. The Government had to resort to using the Lands Title Commission to help determine landowner rights. With initial development delays, production never reached its planned output, only reaching 34,000 barrels of oil per day in September 1999. Additionally, reservoir problems were encountered which involved sanding problems due to the reservoir sandstone being extremely fragile and friable. Extensive extended well testing (EWT) at Moran enabled early oil production and the gathering of some very useful field production data. However, it depleted the reservoir pressure to such an extent that the associated gas started to effervesce from the oil and create a gas cap above the oil. This required re-pressurisation of the Moran oil field using gas sourced from the adjacent Agogo field. The Moran oil field’s high compartmentalisation broke the field into many small fragments which were often difficult to resolve. Gas Development Preparations In the absence of any further significant oil discoveries, the future was considered to lie in the development of the gas fields, where exploration drilling was demonstrating them to be significantly more abundant than oil by a factor of about ten times. The Government realised that its petroleum endowment was not so full of oil, but was comprised substantially of natural gas resources. It was recognised that it would be difficult to develop these in the absence of any domestic gas demand from households, commerce or industry, and all the more so because PNG is remote from the gas markets of other nations. Figure 5: An index map of discovered oil and gas fields of Papua New Guinea as of 1993. Of these fields, only Iagifu-Hedinia, Agogo, SE Gobe, SE Hedinia and Usano contained oil; the rest were gas fields, some with large amounts of gas.    Accordingly, in 1992, the PNG Government, through the newly established Petroleum Branch of the Geological Survey, commissioned a special study on all the discovered oil and gas fields of PNG. This work was conducted by the US firm Scientific Software Intercom in collaboration with the Government’s Petroleum Division and sought to assess the extent of the petroleum resources and reserves to proper and systematic standards of reserve reporting as were then published by the Society of Petroleum Engineers. Based on aggregation of the recoverable reserves, an economic study was then undertaken applying the then prevailing PNG petroleum fiscal and commercial regime. The results were presented to the National Executive Council, showing that if the gas fields discovered to date were aggregated, there could conceivably be a large-scale commercially viable gas development based on the export of liquefied natural gas (LNG) to energy-hungry East Asian markets. However, more work would be needed to obtain better estimates of the recoverable gas reserves, the quantification of gas field development costs and the construction costs of a gas conditioning plant, gas pipelines, liquefaction facilities, and storage and export facilities. The Government liked the idea of gas development and embarked on reviewing and examining suitable policies for such and began fostering the notion of gas development. Economic and policy studies were conducted and extensive discussions between gas field licensees, owners and promoters ensued. After extensive consultations between Government agencies and licensees, in 1995, the Government tabled a Natural Gas Policy before the Papua New Guinea Parliament. The policy laid down the regulatory, commercial and fiscal terms that the Government was willing to consider for the encouragement of investment in gas development. Key features were the introduction of Petroleum Retention Licences (PRLs) to allow the companies to keep their discoveries beyond the period of tenure provided by a normal Petroleum Prospecting Licence. These would be allowed in consideration of an acceptable programme of gas field appraisal and delineation, the conduct of commercial studies and development promotion by the licensees. So long as a field was currently not commercially viable, the PRLs would allow retention by the licensees for up to 15 years, and no longer. This was a significant encouragement to the holders of petroleum prospecting licences, which normally only gave a combined tenure of eleven years in which to explore, make a discovery and launch a field development. The introduction of PRLs recognised the very long lead time for large-scale gas development. The gas policy also introduced a single ring-fence for project development, including gas pipeline infrastructure, liquefaction plant and marine facilities. Based on considerable economic modelling and debate, the policy landed on a concept of 50/50 sharing of the net value between the developer and the Government. The income tax rate for gas operations was set at 30% of net profits, without any dividend or interest withholding taxes, and the State decided it would keep its right to take up to 22.5% equity in the entirety of any development, including the LNG plant and associated facilities. Royalty rates and development levies were left at 2% of the wellhead value. Fiscal stability was to be offered, but only upon payment of a 2% income tax premium and the execution of a Fiscal Stability Agreement with the Government. This was effectively an elegant user-pays principle. Standard depreciation allowances on capital expenditure and exploration would remain at 10% per annum and 25% respectively under the existing fiscal regime. These still represented a quite harsh depreciation schedule by petroleum sector standards because it is not possible to fully recoup one’s field development costs until ten years after expenditure, unlike more accelerated cost recoveries allowed in Production Sharing Contracts. With the foundations for commercial gas development defined by the new gas regulatory and fiscal regime, Exxon and BP pursued their LNG development plans based on the large Hides gas field with the idea of taking the gas to the north coast of Papua New Guinea. There in Madang, they planned to build a coastally located deep-water liquefaction plant sited next to deep-water fjords which would give direct access for LNG carriers to moor alongside these coastal facilities. However, these plans faltered due to the Asian financial crisis in 1997 and the consequent sudden reduction in East Asian LNG demand. The tragic and terrible tsunami that occurred in 1998 at Aitape on the north coast accentuated the seismic risk for an LNG plant on the north coast of Papua New Guinea. The tsunami demonstrated that, whilst placing any LNG facilities nearer to markets, any north-coast-located LNG facility would have to be built to much more exacting standards of construction and operation to cater for the additional seismic risk. The Petroleum Division, mindful of the seismic hazards of the northern part of PNG, had earlier commissioned a PNG Seismic Hazard Study from Dr Horst Letz, formerly resident seismologist at the Port Moresby Geophysical Observatory (and later to be the chief scientist who set up the Earthquake and Tsunami Warning Centre in Jakarta, Indonesia). This report was published around the time of the tsunami. It clearly defined the risk and indicated that a southern coast location for an LNG plant and facilities would be preferable, even if it meant a slightly longer shipping route for LNG carriers to transport LNG to likely markets in East Asia. Figure 6: Summary of earthquake return periods for terminals and pipeline corridors for magnitude M 6, M7 and M 8 earthquakes. The Hides-Yule Island route was the least seismically active. After Dr. H Letz Additionally, gathering gas from gas fields aligned with the prevailing geological structure of the Papuan Basin running north-west to south-east would have a better chance of collecting gas from multiple fields to be found in the same orientation rather than orthogonally across the dividing range of mountains and across the swamps of the Sepik River basin, all of which were void of gas discoveries. Later, BP withdrew from Papua New Guinea and took their ideas about larger-scale gas development by way of an LNG project to West Papua in Indonesia, where they successfully launched the Tangguh LNG Project in a similar environment, peopled again by Melanesians. When the amendments to the Petroleum Act were being prepared for gas development pursuant to the approved Gas Policy, the results of policy studies on landowner benefits (both royalty and equity sharing), strategic access to pipelines and petroleum processing facilities, and elementary domestic gas business provisions became available. An effort was made to incorporate them into the amendments to the Act. The Government was also intent on providing statutorily defined benefits to communities hosting any future oil and gas development, together with proper processes of consultation and liaison with communities, rather than having negotiated and often capricious benefit-sharing arrangements. For such benefits, the Government devised the idea of a separate Development Agreement between the community parties, sub-national Government parties and the State. The allocation of defined and additional benefits was to be agreed in a formally convened development forum. Proper professional research was also to be made as to land matters through the conduct of formal social mapping and landowner identification studies conducted by and at the expense of the petroleum licensees themselves, but with such studies being furnished to the Government for its use. Significant and specific political lobbying arose from the Southern Highlands Province, home to many of the known major oil and gas fields. The Province, quite bizarrely, wanted a separate Gas Act just for gas operations. For a while, it seemed that the National Government was stymied in its plans for gas development due to these concerns, but extensive consultations took place. In the resulting compromise, the Government agreed at the political level to introduce some of the reforms suggested by the Province, but only if the Act would remain intact, though it was now agreed that the new Act would be rebranded as the Oil and Gas Act, whilst still generically referring to petroleum for the most part. Thus, the Oil and Gas Act, No. 49 of 1998, was born. It represented a major restatement and overhaul of the former Petroleum Act and has paved the way for improved and formalised participation by communities and their sharing in statutorily defined benefits arising from oil and gas production. It is only a shame that timely and efficient benefit processing and reconciliation with the correct beneficiaries have been difficult at times to achieve. Disputation of land ownership has not helped in this matter. Figure 7: An early copy of the Oil and Gas Act No.49 of 1998 which was certified on 9th February 1999 and commenced on 18th February 1999. It replaced the Petroleum Act, No. 46 of 1977.     Gas to Australia Schemes Meantime, Chevron, realising that they were handling increasing volumes of associated gas in their operation of the Kutubu oil fields (as much as 400 million standard cubic feet of gas per day (MMSCFD)), bought out the commercial notions that the International Petroleum Corporation (IPC) (the early Lundin Oil Company) had about developing their offshore Pandora gas field. Pandora had been discovered by IPC in 1988 in the middle of the Gulf of Papua, and subsequently the company had plans of producing and piping gas to Townsville in Queensland, Australia, to supply a 200-megawatt power plant. Chevron had gas aplenty and was taking great pains to re-inject as much of it as possible into the reservoirs, but if that gas could be sold into a market, they considered that perhaps that could enhance their sales revenue and obviate the need to inject quite so much gas. There then ensued a period when all manner of gas development notions were focused on transmitting gas to Australia from the associated gas of the producing oil fields plus gas from development of the as-yet-undeveloped gas fields, such as Hides, Angore, Juha and P’nyang. Over the course of the next several years, various schemes to send gas southwards to Australia waxed and waned and struggled to gain traction. In the early 2000s, exploration reached an all-time low as corporate enthusiasm waned. There was little point in exploring for petroleum with the high likelihood of finding gas rather than oil, if even the substantial discovered gas fields could not be developed and produced. In 2003, Chevron departed the Kutubu Joint Venture as its material economic interest in the Kutubu Project diminished below its corporate threshold. It sold its Papua New Guinea assets and interests to Oil Search. Figure 8: The PNG Gas Project as at the end of 2005 waxed and waned in scope for several years The PNG Gas Project, also known as the PNG Gas to Queensland Project, or Gas to Australia Project, ended up at one time with over 4,300 kilometres of trunk gas pipelines and laterals hanging off the Papua New Guinea gas fields with nearly 250 PJ per annum (equivalent to about 600 million standard cubic feet of gas per day at 1,056 British Thermal Units per cubic foot) of potential gas sales. Alas, fundamental flaws in the concept led to most of those potential customers being quite quixotic. Figure 9: The variable potential markets for gas from Papua New Guinea prior to the switch to LNG development in 2006. After S. Khwaja, World Bank, 2005    Most of that infrastructure was in the north-eastern quadrant of Australia and its installation was to be expensed against the supply of gas to a wide and quixotic range of Australian gas customers. With low gas prices, high steel prices and the emergence of coal seam methane development notions in Australia, it was eventually realised that PNG might end up giving its gas away for nothing, and that the only value for Papua New Guinea might remain in the natural gas condensates extracted from the gas in Papua New Guinea. The PNG Gas Project for the supply of gas to Australia failed. Additionally, such a large-scale transnational activity needed considerable support from the Governments of both Australia and Papua New Guinea to protect sovereign interests. Fundamentally, Australia’s policy of gas-versus-gas competition and gas system regulation was at odds with such a trunk gas delivery pipeline, which would need special treatment within the Australian pipeline regime and due respect for its transnational delivery of gas. Eventually, in 2008, an abrupt turn was made to change all the development notions towards supplying gas to an LNG plant to be located on the Papuan coast beside the Gulf of Papua. An effort was immediately made to market the gas as LNG to East Asian markets. Australia had specifically encouraged gas-versus-gas competition, but in doing so it spoiled the market price for gas imports from countries such as PNG and encouraged the furtherance of coal seam methane (CSM) schemes to extract gas from extensive coal deposits in Queensland. Indeed, this later gave birth to Australian LNG export projects supplied by gas from CSM sources, the supply of which has not turned out to be so plentiful, necessitating the purchase of make-up gas from domestic markets and thus creating a domestic gas supply shortage along Australia’s east coast. In abandoning gas supply to Australia by pipeline, Papua New Guinea now needed to consider capturing the premium values that gas exports into energy-deficient East Asian economies were able to achieve. The dependence on external infrastructure and specific gas demands in Australia was not seen as either politically attractive or sustainable, nor was it commercially attractive due to low gas prices brought about by Australia’s gas competition policies. It was most fortunate that Papua New Guinea backed away from such schemes for the dispatch of gas to Australia. Thus was born the PNG LNG project. PNG LNG had many factors in its favour as a distinct source for LNG for supply to East Asian markets. PNG is a non-aligned Christian nation; it is not an Islamic nation. PNG was desirous of investment and keen for development based on commercial fiscal terms. PNG, as a nation, has open-ocean access and does not rely on any strategic straits. It has a Westminster-style Government and observes the principles of law and contract. PNG is favourably positioned to supply the Australasian region, but can reach out to serve Asian, Pacific and American markets. With diminishing oil production and the absence of new oil finds, PNG’s explorers needed to capitalise on prior exploration investments that failed to find oil. Gas in the new 21st century was no longer a hindrance and could be profitably developed, even extending the life of the oil fields. The PNG LNG project was projected to export LNG at a heating value of 1,135 BTU/SCF gas and the liquids were forecast to sell at US$60/barrel. Anticipated LNG prices were: US$8.07 per MSCF, equivalent to US$10.20 per MMBTU, or US$9.69/GJ. The original plant design was upgraded early on from 6.3 million tonnes LNG per annum to 6.9 million tonnes LNG per annum for production over a 30-year period. Gross income was estimated to be about US$74.3 billion. Even at US$50/barrel oil, the project was still forecast to yield US$61.9 billion in LNG sales. The gas is rich in natural gas liquids (NGLs), so at just 20 barrels of NGLs per million cubic feet of gas, some 210 million barrels of NGLs were forecast to yield an additional US$12 billion of sales revenue. In May 2014, PNG became an LNG exporter and is now producing consistently more than 8 million tonnes per annum (mta) LNG to customers in China, Japan and Taiwan – well above the nameplate capacity of the original LNG plant design. It got there because of fine operatorship on the part of ExxonMobil of a coherent joint venture. ExxonMobil was able to market the gas to top-quality customers and obtain superior project financing. The only major disappointment has been the collapse in crude oil prices below projections on several occasions, and hence the LNG prices due to the indexing with crude oil. For the first year, some elevated prices were obtained, but clearly the fall of crude oil below US$30 per barrel in the early days of LNG production hurt the project economics and outcomes to all stakeholders, as it again did during COVID-19 when LNG prices plummeted below US$3 per million British Thermal Units. Figure 10: The PNG LNG Logo was designed around Papua New Guinea’s distinctive cultural icons, a traditional mask, in Papua New Guinea’s national colours.  The two swishes represent has emerging from the ground. The nicks in the right swish suggest the plumage of Papua New Guinea stunning Birds of Paradise.   The PNG LNG Project produces gas from a variety of gas fields including the Hides and Angore gas fields, and the Kutubu, Moran, Agogo and Gobe oil fields. The more remote Juha gas field is set to produce gas later. Altogether, these fields have about 9 trillion standard cubic feet (TCF) of gas to contribute for liquefaction. Other discovered gas fields will likely be developed later and, despite being cast as different projects, will likely seek to optimise gas infrastructure; these are the P’nyang gas field and the Muruk gas field which can add about 5.25 TCF of additional gas for liquefaction. Quite how much gas will eventually be recovered from each field still has considerable uncertainty, just as stated before for oil recovery. This is due to the considerable remaining uncertainty of definition of the subsurface reservoir volume due to a lack of seismic imaging and lateral resolution of field boundaries. The geology is already complicated on account of the extensively folded and faulted nature of the strata, so we might anticipate some surprises, both positive and negative. Figure 11: The Hides Gas Conditioning Plant which conditions gas from Hides and Angore gas fields before transmission down the trunk gas pipeline to Caution Bay  Figure 12: The PNG LNG Project LNG Plant Terminal in Caution Bay where an average of nine cargoes of LNG is loaded each month. It sits at the end of a 2.4-kilometre jetty build out into Caution Bay Access to lands for the PNG LNG Project development came with resounding landowner consent after enormous development forums were held at project level in Kokopo in New Britain and at licence level in each licence area. During the forums, the sharing of the benefit streams of the 2% royalty, 2% free equity from the State, 2% development levy, and other project grants including business development and infrastructure grants were discussed. Oddly, whilst some grants were paid quite promptly, distribution of the royalties and equity benefits has been the subject of considerable delay, mainly due to some remaining uncertainties about landownership, often brought about by disputes over landownership. This is exceedingly difficult to accomplish where traditional customary title persists, often with multiple and overlapping ownership and usufructuary rights. But notwithstanding this situation, the landowners have been extremely patient, and in some cases, and for many years into LNG production and export, they have remained quite stoical. Aside from the statutorily defined equity benefit of 2% of the project, the Government agreed to provide additional equity to the communities in the amount of 4.2%. This was promised to them in the main PNG LNG Project development forum in Kokopo. This was to have been a commercial deal, but successively its commercial cost to the beneficiaries has been whittled down to nothing. Provided that this additional equity benefit can be managed properly and in accordance with the Oil and Gas Act, it will be a most valuable asset once the project finance has been paid down by the State. Elk/Antelope Gas Field A bold and entrepreneurial company called InterOil, championed by a charismatic leader Phil Mulacek, had two Petroleum Prospecting Licences (PPLs) in the Eastern Papua Fold Belt: PPLs 237 and 238. They were granted in 2003 near to small historic gas discoveries of the 1950s, such as Kuru, Puri and Bwata, each in Miocene limestones. In 2006, the Elk-1 well was drilled and declared to be a gas discovery in fractured Puri Limestone after testing at 21.7 MMSCFD. Two more wells, Elk-2 and Elk-4, were drilled to appraise the structure. Elk-2 penetrated the Puri Limestone below the gas-water contact. The Elk-4 well penetrated the Puri Limestone again, but at depth it intersected a gas-bearing reefal facies of shelfal limestone which was tested as a gas discovery. A thrust fault separates the Elk structure from a major feature to the south that was named Antelope. Seismic and regional analogy studies indicated that a significant reefal buildup occurs over the Antelope structure. Subsequently, wells Antelope-1 and -2 appraised the lateral extent of the field to the south with good reservoir quality to an approximate extent sufficient to realise that a substantial gas field had been discovered. InterOil applied for a Petroleum Retention Licence, which was designated PRL 15 on granting by the Minister on 10 November 2010. After many bold attempts to devise a scheme of development consisting of mini-LNG trains, including floating offshore LNG trains and all manner of deals, InterOil decided to farm down its equity and introduce an experienced project champion from amongst world-class players. After much wrangling and corporate intrigue, including arbitration hearings between new equity participants, InterOil finally left the Elk-Antelope gas field and its future development to a joint venture comprised of Total (as operator) 61.3%, Oil Search 22.835%, ExxonMobil 36.45% and other parties 0.5%. Altogether, some 10 wells have penetrated the Elk-Antelope structure, and the area is covered by several generations of 2-D seismic data. Subsequently, Oil Search merged with Santos and, once the project licences are granted, the Government will most likely exercise its lawful option to take equity at cost, reducing each participant's equity proportionately to give the final project equity as: TotalEnergies 31.1%, ExxonMobil 28.7%, Santos 17.7% and the State 22.5%.

Steamships is pleased to announce the appointment of Damian Cooper as Head of Division for Steamships Hospitality. Managing Director Chris Daniells said: “Damian joins us at an exciting time as we continue to strengthen and grow our hospitality portfolio. Damian’s deep operational expertise, development background and strategic vision will play a critical role in supporting Steamships’ long-term growth ambitions and reinforcing its position as a market leader in Papua New Guinea.” An accomplished hospitality executive, Cooper brings more than 20 years of global leadership experience across luxury, upper-upscale and mixed-use hospitality operations throughout Asia Pacific, the Middle East, Africa and the Pacific. His career includes senior leadership positions with leading international brands such as Marriott, Starwood, Westin, Sheraton, InterContinental, Radisson Blu, Anantara and Swiss-Belhotel. Cooper is widely recognised for his ability to lead complex operations, drive commercial outcomes and build resilient teams in challenging environments. He has managed some of the region’s largest hospitality assets, including properties with over 600 rooms, extensive MICE facilities, and workforces exceeding 500 employees. His career highlights include Michelin-starred operations, multiple Marriott awards, board-level experience, and regional leadership roles across APAC, Africa and the Indian Ocean. His expertise spans full hotel operations, post-COVID repositioning, major refurbishments, rebranding, crisis management, and large-scale development projects. Under his leadership, operations have consistently delivered above-market and record GOP performance while building high-performing and resilient teams. Prior to joining Steamships, Cooper served as General Manager – Hotel & Development at The Stanley Hotel & Suites, leading a flagship five-star hotel and mixed-use precinct. Steamships welcomes Cooper to the executive leadership team and looks forward to the positive impact he will bring to the company and its hospitality division.

 The PNG Chamber of Resources & Energy will deliver two major events in 2026, providing platforms for dialogue, collaboration, and investment engagement across Papua New Guinea’s key resources sectors. PNG Resources Week APEC Haus, Port Moresby 29 June – 16 July 2026 Register your interest: https://pngcmp.eventsair.com/2026.../prw26eoi/Site/Register pnginvestmentweek.com.pg PNG Investment Week ICC Sydney, Australia 29 November – 2 December 2026 Register your interest: https://pngcmp.eventsair.com/2026.../piw26eoi/Site/Register pngresourcesweek.com Attendees will include government representatives, global investors, industry leaders, landowners, project developers, and other key decision‑makers involved in PNG’s economic development. Organisations and investors with interests in investment, resources, infrastructure, and community affairs are welcome to attend these two flagship events. For more information, contact our team: events@pngcore.org +675 207 9080