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The National Information and Communications Technology Authority (NICTA) has signed a contract with Digicel (PNG) Limited to deliver the Connect the Schools Project (NPC 2023-21 – Fixed Broadband Services). The signing ceremony was held in Port Moresby and attended by representatives from NICTA, the National Procurement Commission (NPC) and Digicel PNG. The project highlights NICTA’s commitment to leveraging information and communications technology (ICT) for national development by transforming education through reliable broadband connectivity. It aligns with the Government’s policy objective of expanding broadband access to underserved educational institutions while supporting broader digital economy and education goals. Funded through the Universal Access and Service Fund at PGK 1.4 million, the project will be delivered over a 24-month period. The initiative will provide fixed broadband internet, equipment and software to seven selected schools across Papua New Guinea. The schools that will benefit from the project are: Malala Secondary School Kerowagi Secondary School Popondetta Secondary School Cameron Secondary School Manus Secondary School Hoskins Girls TVET Asitavi Secondary School The project will provide students, teachers and surrounding communities with high-speed connectivity for e-learning, online resources and digital skills development, supporting government efforts to expand digital education services, particularly in rural and remote areas. Digicel (PNG) Limited has also committed an additional K140,000 (K20,000 per school) to support sustainability beyond the initial contract period. Speaking at the signing ceremony, NICTA Acting Chief Executive Officer Polume Lume said the project represents an important step towards strengthening digital education in Papua New Guinea. “This contract is more than an agreement — it is an incentive for a sustainable digital education environment that will empower our students, teachers and communities,” Mr Lume said. He also acknowledged the contribution of project partners. “I thank Digicel (PNG) Limited, the National Procurement Commission, and all stakeholders for their dedication throughout the process. Let us work together to build a brighter, fully connected future for our schools and our nation.” The Connect the Schools Project supports the National Government’s Digital Transformation Agenda and is expected to contribute to long-term social and economic growth by promoting inclusive education and a digitally empowered population.

K92 Mining Inc., operator of the Kainantu Gold Mine in Papua New Guinea’s Eastern Highlands Province, reported record production and financial results for 2025, driven by strong fourth-quarter performance and the commissioning of its Stage 3 expansion plant. In a statement released on March 2, the company said it produced 47,178 gold equivalent ounces (AuEq) in the fourth quarter of 2025, bringing total production for the year to a record 174,134 AuEq. K92 said the results coincided with the completion of commissioning for the new 1.2 million tonnes-per-annum Stage 3 expansion process plant at Kainantu. The facility is now ramping up operations and is expected to support further production growth. The company also reported significant economic contributions to Papua New Guinea during the year. These included PGK 423 million in corporate tax paid or accrued to the national government, PGK 50 million in royalties, and PGK 11 million in Mineral Resource Authority levies. Capital investment reached PGK 862 million, mainly related to advancing the Stage 3 expansion. K92 also spent PGK 74 million on exploration activities targeting near-mine and regional opportunities. The miner said it spent PGK 667 million with local suppliers and PGK 137 million on local joint venture contracts, aimed at increasing participation by domestic businesses and landowner groups. Community programmes received PGK 11 million in funding, supporting health, education and infrastructure projects. K92 Mining chief executive officer John Lewins said the year marked a significant milestone for the company and the Kainantu operation. “2025 was a transformational year for K92 and for the Kainantu Gold Mine. We delivered record annual production and financial results while successfully commissioning the new 1.2 million tonnes-per-annum Stage 3 Expansion Process Plant,” Lewins said. He said the expansion would increase processing capacity and support long-term growth for the operation. “The expansion represents a long-term investment in Papua New Guinea, supporting increased employment, stronger local business participation, and higher tax and royalty contributions,” Lewins added. “As production grows, so too will the economic benefits for the Government of Papua New Guinea, our landowner partners, local communities and business stakeholders.” K92 operates the Kainantu Gold Mine, one of Papua New Guinea’s producing underground gold mines, located in Eastern Highlands Province. The company has been expanding the operation in recent years as part of its strategy to increase output and extend the life of the mine.

 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.  

A 100-kilowatt solar mini-grid has been commissioned at Kanabea Rural Health Centre in Gulf Province, delivering round-the-clock electricity to one of the country’s most isolated communities after a logistics operation that required 31 helicopter lifts and nearly 22 tonnes of equipment. Operational since September 2025, the system powers the rural health centre, Kanabea Primary School, the local Catholic church, staff housing and more than 40 surrounding households, marking a major step forward for a community accessible only by air or a three-day trek over two mountain ranges. The project was initiated in late 2023 under the USAID-Papua New Guinea Electrification Programme, or USAID-PEP, which committed 700,000 kina in support of rural electrification aligned with the government’s Medium Term Development Plan IV target of 70% national electrification by 2030. Of that amount, 545,000 kina was disbursed before the programme was terminated by the Trump administration under the US Department of Government Efficiency initiative. The initial proposal sought 50% co-funding. In total, the project received 545,000 kina from USAID-PEP, 700,000 kina from the Kerema District Development Authority and 20,000 kina from PNG Foundation in Melbourne, Australia. Any shortfall was absorbed by PNG Solar Supply and installation contractor Construction Electrical Services. The Kerema DDA support was provided under the leadership of Thomas Opa, who now serves as Papua New Guinea’s finance minister. Despite the early closure of USAID-PEP, the project proceeded to completion. The funding disruption resulted in minor scope adjustments, with installation teams hiking in and out of Kanabea and carrying approximately 120 kilogrammes of smaller equipment on foot. On-site works ran for 15 weeks from May to September, with delays caused by limited aircraft availability for the final material deliveries. Typical installations take eight to 10 weeks where logistics are less complex. The system has recorded 100% uptime since commissioning. Air-only logistics All materials were transported by road to Kerema before being airlifted approximately 27 nautical miles (50 kilometres) to the site. The 15-minute flight belies the scale of the task: the cargo — including solar panels, battery systems, mounting structures, poles and distribution lines — weighed nearly 22 tonnes. Thirty-one helicopter lifts were required, most carrying underslung freight. Fully solar configuration The mini-grid is fully solar powered, with no diesel generator backup. It comprises two 50kW Sunsynk inverters paired with 122.8 kilowatt-hours of high-voltage Sunsynk lithium battery storage. The solar array uses Trina Vertex S+ 430-watt n-type panels. The system is designed to allow additional panels and battery storage to be added as demand grows. Reliable power is expected to transform public services. The health centre, which is estimated to see around 40,000 patients annually, can now operate vaccine refrigeration, diagnostic equipment and emergency services at night. The primary school, with approximately 500 students, can extend study hours and introduce digital learning tools. Prepaid tariff model The system operates under a prepaid off-grid metering arrangement, with electricity priced at 1 kina per kilowatt-hour — comparable to urban tariffs. Billing and collections are managed by the local Catholic church, with revenue allocated to routine maintenance and a reserve fund to ensure long-term sustainability. Replicable model PNG Solar Supply has delivered 23 similar mini-grids nationwide. The Kanabea model has since been replicated at six sites in Bougainville — five high schools and one USAID-PEP-initiated project in Bumpuka village in the Autonomous Region of Bougainville. A further 16 sites have progressed from procurement and design to installation. The Kanabea project highlights both the logistical challenges and the transformative potential of decentralised renewable energy in Papua New Guinea’s most remote regions.

The Papua New Guinea government is set to redevelop the 20,000-hectare Urimo Cattle Ranch in the Sepik Plains in partnership with New Britain Palm Oil Limited (NBPOL), according to Minister for International Trade and Investment Richard Maru. Maru said the ranch, once a thriving livestock hub, has been idle since the late 1970s and will be revived as part of the government’s efforts to strengthen domestic beef production. “Prime Minister James Marape is fully supportive of this project. This will be the largest cattle farm in the country,” Maru said. The government, through the Ministry of International Trade and Investment and the Livestock Development Corporation (LDC), has reached an agreement for work to begin immediately. Initial activities will include fencing large sections of the 20,000-hectare property owned by LDC in Urimo and upgrading the Kusaun to Urimo road to support the redevelopment. “The work on the fencing is expected to start this week and the National Government has committed K10 million for the road upgrade, with the contract to be signed in the coming week. The cattle will be ordered from Sialum in Morobe for the redevelopment of this ranch,” Maru said. He also welcomed the cooperation of the Minister for Livestock and the Livestock Development Corporation in advancing the project. Maru said Papua New Guinea currently imports about K250 million worth of beef from Australia annually due to insufficient domestic production. “This is because we do not produce enough to meet the local demand. That is the reason why the price of beef, including ox and palm, is so high,” he said. The minister added that increasing local production of meat products presents a significant opportunity for the country. “Replacing imports of beef and chicken are low-hanging fruits because we can easily raise cattle and chickens in PNG. I am working with potential investors to make sure we produce enough beef and chicken to supply our domestic market and also for exports,” Maru said.

Digitec PNG Financial Services Limited, trading as V-MONI; Omega Paymybills PNG Limited; and Lower OK Tedi Micro Bank Limited have officially received licence certificates from the Bank of Papua New Guinea (BPNG) on 27 February at Robert Haus in Port Moresby. Speaking at the licence presentation ceremony, BPNG Governor Elizabeth Genia described the development as positive news for Papua New Guineans. “The expansion of licensed payment services means greater convenience, faster transactions and improved access to digital financial services for our people, including those in rural and remote areas,” Governor Genia said. She added that microfinance institutions are equally vital in extending financial services to underserved communities, supporting small enterprises and promoting inclusive economic growth. Digitec PNG Financial Services Limited, trading as V-MONI, and Omega Paymybills PNG Limited have been licensed as Payment Service Providers (PSPs) under the National Payments Act 2023. The PSP licence enables institutions to allow customers to securely store money, make payments and transfer funds directly from their mobile phones without the need for a traditional bank account. This regulatory approval paves the way for greater participation in the digital economy, particularly for individuals with limited access to conventional banking services. Lower OK Tedi Micro Bank Limited has been licensed as a licensed financial institution under the Banks and Financial Institutions Act 2000 to operate as a micro bank. As a microfinance institution, it is authorised to take deposits and provide lending services, particularly to small businesses and individuals who lack access to traditional credit opportunities. The move is expected to support entrepreneurship and stimulate economic activity in underserved areas. Governor Genia reminded the newly licensed institutions that receiving a licence carries significant responsibility. She emphasised that a licence is not merely a certificate but an obligation to uphold strong oversight, effective governance and strict compliance with all regulatory requirements, including anti-money laundering and counter-terrorism financing (AML/CTF) obligations. “As licensed financial institutions, you form part of the first line of defence in protecting our financial system. Effective customer due diligence and a strong compliance culture must be embedded in your operations from day one. Weaknesses in this area expose your institution and the entire financial system to significant risks,” she said. The governor also assured the institutions of the central bank’s continued support. “Of course, this is only the start of a long collaboration. You have our full support in meeting these expectations,” she added. BPNG reaffirmed its commitment to maintaining close engagement with financial institutions to ensure that PNG’s payment and financial system remains safe, sound and trusted. The issuance of the licences reflects the central bank’s ongoing efforts to promote innovation while safeguarding financial stability and advancing financial inclusion across the country.

Loloata Island Resort recently hosted a beach clean-up that brought together 20 volunteers in a collective effort to remove debris and raise awareness about ocean pollution. The clean-up, held on 22 February 2026, formed part of the resort’s ongoing marine conservation initiatives and was led by Marine Conservation Officer D’Andre Yamuna. Participants worked along key sections of the island’s coastline, collecting litter that had washed ashore from surrounding waters. Teams focused their efforts on two areas of the island: the mangrove-fringed eastern shoreline, stretching from the Organic Garden to the Lima 8 Gate, and the sandy and rocky western shoreline, from West Beach to the Lima 5 Gate. Volunteers systematically combed the coastline, removing debris and documenting the types of waste found during the activity. By the end of the clean-up, the team had collected more than 2,300 individual items of waste, filling 18 bags of rubbish across approximately 4,700 square metres of shoreline. The activity also included a waste audit to better understand the types of debris reaching the island and to support future conservation planning. The findings showed that plastics made up the majority of the waste collected, accounting for about 92 percent of all debris. Soft plastics, such as food wrappers and plastic bags, were the most common items found, followed by hard plastics, including bottles and fragments. According to Yamuna, the clean-up highlights the wider challenge of marine pollution affecting island environments. “Many of the items we collected likely originated from nearby coastal communities and were transported here by tides and currents,” he explained. “Beach clean-ups like this are important because they not only remove waste from the environment but also help us understand the sources of pollution.” For Loloata, the clean-up reflects a growing commitment to environmental stewardship and sustainable tourism. The resort continues to support marine conservation through regular clean-ups, monitoring activities and awareness initiatives aimed at protecting the surrounding reef and coastal ecosystems. Anyone interested in learning how they can join or participate in these conservation initiatives is welcome to contact the team at marineconservation@loloata.com.

 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%.

The Chief Executive Officer of the National Superannuation Fund (Nasfund), Rajeev Sharma, on 20 February announced the appointment of Christopher Elphick as Chairman of the Nasfund Board of Directors, effective January 2026. Sharma said, “On behalf of the Fund, I am pleased to announce the appointment of Christopher Elphick as Chairman of the Board. Christopher brings proven leadership, strong governance experience, and a deep understanding of Nasfund’s mission to deliver long-term value for our members. His strategic mindset and investment expertise will be invaluable as we continue advancing our priorities and strengthening member outcomes.” Elphick joined the Nasfund Board on October 1, 2022, as an Independent Director. He has since chaired the Investment Committee and served on the Remuneration and Nominations Committee. He brings extensive experience in business, management, and governance. Elphick holds a Bachelor of Science (BSc) in Business Management from the University of Surrey (UK), majoring in Marketing and Management, and is an alumnus of the United World College of South East Asia. A proud graduate of the Nasfund Trainee Directors Program (2014 cohort), he has maintained a long-standing relationship with the Fund and a strong appreciation of its mandate. Beyond his role at Nasfund, Elphick serves as Executive Director of Tohouwa (PNG) Limited (FairPrice), outgoing Chairman of the Nasfund Contributors Savings & Loans Society (NCSL), and Director of Transparency International PNG, among other roles. Elphick succeeds Tamzin Wardley, who served as Board Chair from October 2022 to December 2025. Acknowledging Wardley’s contribution, Elphick said, “I want to acknowledge the outstanding leadership of my predecessor, Tamzin Wardley. Her vision and dedication have reaffirmed Nasfund as a trusted and innovative superannuation provider.” Reflecting on his appointment, Elphick added, “It is an honor to lead Nasfund at this pivotal time. Having begun my journey as a trainee director, I am humbled to now chair the Board of an organisation that plays a critical role in securing the retirement future of all contributors in Papua New Guinea. My focus will be on strengthening governance, driving sustainable investment strategies, and enhancing member services through innovation, based on Nasfund’s values. With a strong Board and an exceptional management team led by CEO Rajeev Sharma, we are ready for tomorrow.”

BSP Financial Group (BSP) joins the global community in celebrating International Women’s Day (IWD) 2026, championing prosperity and gender equality across the South Pacific. Marking the occasion, BSP Group CEO Mark Robinson highlighted the bank’s ongoing commitment to advancing equality throughout the region. “Our workforce reflects the progress we are making in inclusion and equality, with women making up 51% of our 4,800 employees. Forty per cent of leadership roles in the bank are held by women, with women also accounting for 66% of Branch Managers,” Mr Robinson said. Central to this year’s #GiveToGain theme is the development of young talent through the BSP Graduate Trainee Programme, which provides a launchpad for female professionals entering the financial sector. Tate Simeona-Gairo, Assistant Company Secretary, described her career journey as transformative, having begun her career as a graduate trainee. “My experience and growth are a testament to how BSP nurtures a workplace culture that gives to gain,” said Ms Simeona-Gairo. “BSP invests the time, resources and expertise required to mentor and develop young talent.” The bank’s commitment to career development is further reflected in the increasing number of women progressing into senior roles. Ruby Arabella-Patu is one such example. She began her career in a branch and now serves as Senior Manager, Customer Value Management in BSP’s Retail Bank. “Progressing from an entry-level role to senior management has been a journey shaped by learning, opportunity and support,” said Ms Arabella-Patu. “BSP provided an environment where I could grow through leadership development and trust in my capabilities. As a woman in leadership, I am proud to help build a more inclusive and resilient future for the organisation.” Ms Arabella-Patu also acknowledged the support of her male colleagues, family and community, noting that genuine empowerment is built on mutual trust and respect as organisations work together to advance gender equality across the region. BSP said it remains proud to lead for prosperity by investing in its people and fostering a workplace culture that champions respect, care and growth for all. BSP is the South Pacific’s international bank, with roots in Papua New Guinea dating back to 1916. Today, it is the leading bank in the region, serving three million retail, business, corporate and institutional customers across Papua New Guinea, Cook Islands, Fiji, Samoa, Solomon Islands, Tonga and Vanuatu. The bank’s purpose is to Champion Prosperity in the South Pacific, serving customers through the region’s largest banking network, which includes 124 branches and 596 ATMs, many located in remote areas where BSP is the only banking provider, alongside a wide range of digital banking services.