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Air Niugini has launched its first scheduled international service using the Airbus A220-300, marking a key milestone in its fleet modernisation programme and strengthening air connectivity between Papua New Guinea and Australia. The national carrier operated flight PX 90 from Port Moresby to Cairns on Friday, March 27, representing the aircraft type’s first international deployment following its introduction into the domestic network in September 2025. Until now, the A220-300 has been used exclusively on domestic routes, serving key destinations including Lae, Kavieng, Manus, Gurney, Rabaul and Port Moresby. Its international debut signals the next phase of the airline’s fleet renewal and network expansion strategy. The Cairns route—linking Port Moresby with Far North Queensland in approximately 90 minutes—has been identified as a strategic corridor, underpinned by strong trade, tourism and people-to-people ties. Chief Executive Officer Alan Milne said deploying the A220-300 on international services enhances both operational capability and passenger experience. “The Airbus A220-300 is a modern, fuel-efficient aircraft that offers greater comfort, reliability and operational efficiency. Deploying this aircraft on our international routes strengthens Air Niugini’s capability to connect Papua New Guinea with key regional destinations while delivering a world-class travel experience,” Milne said. He added that Cairns was a natural choice for the aircraft’s first international service, given the long-standing economic and tourism links between Papua New Guinea and Australia. Cairns Airport also holds historical significance for the airline. Air Niugini became the first international carrier to operate into Cairns in September 1975, establishing a connection that has expanded over the past five decades. The airline currently operates nine weekly services between Port Moresby and Cairns, including three same-day return flights and six overnight services, making it one of its most important international routes. The Airbus A220-300, configured with 138 seats in a two-class layout, features wider seats, larger windows, a quieter cabin and onboard Wi-Fi offered complimentary to passengers. The aircraft is also expected to deliver improved fuel efficiency and lower emissions compared with the Fokker and Boeing 737 aircraft it will replace on the route. Cairns Airport Chief Executive Officer Richard Barker said the introduction of the new aircraft would further boost capacity and regional connectivity. “The introduction of this modern aircraft will inject close to 65,000 seats into the Cairns market each year and further strengthen connectivity between our regions, supporting economic growth and creating new opportunities for trade, education and employment,” Barker said. Beyond Cairns, Air Niugini offers onward connections across Papua New Guinea, as well as international services to Manila, Hong Kong, Singapore, Honiara, Port Vila and Nadi, with flights to Narita in Japan scheduled to commence in July. The airline said additional A220 aircraft deliveries will play a central role in enhancing both domestic and regional operations, reinforcing its position as Papua New Guinea’s national carrier. Following the Cairns launch, the A220-300 is scheduled to begin services to Sydney on March 29, followed by Honiara.

Great Pacific Gold Corp. has completed an upsized public offering raising approximately $20.02m, with proceeds earmarked to accelerate its gold-copper exploration portfolio in Papua New Guinea. The Vancouver-based company said it issued 42.6 million units priced at $0.47 each, generating gross proceeds of $20,022,000.  Each unit comprises one common share and one-half of a warrant, with each full warrant exercisable at $0.70 per share until April 2, 2028. The offering was conducted under a prospectus supplement dated March 27, 2026, to the company’s base shelf prospectus filed across Canadian jurisdictions, excluding Quebec. Agents and costs The financing was led by Haywood Securities Inc. as sole bookrunner, alongside Canaccord Genuity Corp., Agentis Capital Markets and Paradigm Capital Inc. In connection with the offering, Great Pacific Gold paid total cash commissions of $1,157,520 and issued compensation options to acquire up to 2,462,808 shares at the offering price, exercisable until April 2, 2028. Use of proceeds Net proceeds will primarily fund exploration and development activities across the company’s gold-copper projects in Papua New Guinea, with remaining funds allocated to working capital and general corporate purposes. The company holds a portfolio of exploration-stage assets in PNG, including the Wild Dog project in East New Britain, as well as the Kesar, Arau and Tinga Valley projects in the Eastern Highlands and surrounding regions. Exploration focus Great Pacific Gold is positioning itself as a gold-copper developer in Papua New Guinea, targeting epithermal and porphyry-style mineral systems across its land package. Its flagship Wild Dog project hosts a large-scale structural corridor with high-grade drilling results, while the Kesar and Arau projects are located near existing mining tenements and are considered prospective for further discoveries. The financing follows the company’s earlier plan to raise up to $15m, which was subsequently upsized to meet investor demand and support expanded exploration activities. Outlook The company said the completed financing strengthens its balance sheet and provides funding visibility as it advances drilling and exploration programmes through 2026.

Prime Minister James Marape said the government will review the unresolved 4.27% equity in the PNG LNG project, signalling a broader reset of benefit-sharing arrangements to improve returns for landowners and provincial governments. Responding in parliament to Komo-Hulia MP Daniel Tindipu, Marape said the equity component—linked to agreements struck before the project’s 2014 first gas—remains unsettled more than a decade later. “This equity component was intended as a meaningful participation mechanism … it is clear that this matter has not been fully resolved,” he said. Legacy of UBSA under scrutiny Marape traced the issue to the 2008–2009 Umbrella Benefit Sharing Agreement (UBSA), which underpinned the project’s final investment decision and included the 4.27% equity as an additional, non-statutory benefit. He said the allocation was designed to supplement mandated entitlements under the Oil and Gas Act, including the 2% royalty and equity provisions, but acknowledged that intended beneficiaries have yet to fully realise its value. Despite the PNG LNG project generating substantial revenues since 2014, the equity’s structure and utilisation remain unclear. Kumul Petroleum tasked with full audit Marape said the government has directed Kumul Petroleum Holdings Limited to conduct a comprehensive review of the equity, including its historical treatment and current valuation. “This is a holistic review … we are examining the full structure of our national equity interests,” he said, adding that the exercise will also cover the state’s broader stake in the project. The findings will be submitted to cabinet to inform policy decisions on allocation and governance. Distribution model under consideration Marape outlined a three-part framework under consideration for the equity: direct financial distribution to landowners and provinces; preservation of value through long-term savings mechanisms; and stronger governance and accountability structures. He said the government would prioritise a structured and sustainable approach rather than a rapid disbursement. “We will not rush this decision. It must be structured carefully to ensure fairness and long-term impact,” he said. Legal distinction shapes approach Marape emphasised that the 4.27% equity is not a statutory entitlement, unlike royalty and equity provisions already distributed under existing law. “This component was a negotiated benefit … that is why we must handle it carefully,” he said, suggesting existing distribution systems could be adapted for future allocations. Agreements open to review The government is also assessing whether existing agreements, including the UBSA, can be revisited. Marape said officials will examine review clauses to determine whether provisions allow updates to reflect current economic and policy conditions. “If provisions exist, we will activate them to ensure agreements remain fair and relevant,” he said. Domestic gas utilisation in focus Separately, Marape said the government is in talks with operators including ExxonMobil and Santos Limited to expand domestic use of Papua New Guinea’s gas resources. The discussions include potential in-country processing and utilisation within petroleum development licence areas to reduce reliance on fuel imports. “Our goal is greater energy security, more affordable fuel, and increased downstream activity,” he said. Broader policy signal Marape framed the review as part of a wider effort to ensure resource projects deliver tangible and equitable benefits. “This is about fairness, accountability, and nation-building,” he said, adding that decisions will be guided by legal frameworks and national interest.

Papua New Guinea is mobilising its energy sector to support the country’s transition towards a low-carbon future as part of preparations for its third Nationally Determined Contribution (NDC 3.0) under the Paris Agreement. The United Nations Development Programme (UNDP) joined the Climate Change and Development Authority (CCDA) in convening a committee meeting with representatives from the energy sector, government agencies and development partners to discuss how the sector can contribute to the country’s climate commitments. Papua New Guinea is currently developing its NDC 3.0, which outlines the country’s targets and strategies for reducing greenhouse gas emissions and adapting to climate change in line with global efforts to limit average temperature rise to below 2°C. Officials said the energy sector will play a central role in advancing the country’s climate ambitions, particularly as global efforts intensify to reduce reliance on fossil fuels and shift towards cleaner, low-emission energy sources. During the meeting, participants exchanged ideas and explored practical solutions to help accelerate Papua New Guinea’s energy transition. Key proposals discussed included expanding the use of renewable energy sources, increasing electrification through off-grid and mini-grid solutions, and improving grid efficiency to reduce energy losses. The meeting was co-chaired by the National Energy Authority and William Laikain, general manager of the Climate Change and Development Authority. Outcomes from the discussions will help inform the finalisation of Papua New Guinea’s NDC 3.0 ahead of national endorsement and submission under the Paris Agreement framework. Officials said strengthening collaboration between government agencies, development partners and the private sector will be essential to advancing sustainable energy solutions and supporting the country’s broader climate goals.

Papua New Guinea’s livestock industry must urgently adopt mechanised farming practices or face continued reliance on costly imported meat, according to Livestock Development Corporation Managing Director Terry G. Koim. Speaking in March at Taliabi, 14 Mile outside Port Moresby, during the presentation of three newly acquired state-of-the-art tractors, Koim delivered a strong message to industry stakeholders, warning that the country can no longer sustain outdated, low-productivity farming systems. “Business as usual is no longer acceptable,” Koim said. “We cannot continue operating at subsistence levels while millions are spent annually on imported meat. Mechanisation is not a luxury — it is a necessity.” The tractors, procured under LDC’s Capacity Building Programme, will support pasture improvement and commercial animal feed production in line with the Government’s Medium-Term Development Plan IV. The initiative forms part of broader efforts to modernise the livestock sector and strengthen domestic production capacity. Koim stressed that without scaling up mechanisation, Papua New Guinea’s livestock industry will struggle to meet growing domestic demand or compete effectively in the market. He framed mechanisation not only as a productivity tool, but as a strategic economic imperative linked to food security and import substitution. The event also highlighted ongoing government backing for the sector, with LDC acknowledging support from the Marape government since 2020. This support has enabled the recovery of state-owned livestock assets, cattle restocking, and investment in infrastructure and workforce development. Koim’s warning was reinforced by operational realities on the ground. Testimony from veteran tractor operator Rau Gilimo underscored the inefficiencies of outdated equipment, describing how poor machinery and exposure to harsh weather frequently disrupt farm operations, ultimately limiting output and increasing costs. Senior LDC managers echoed the Managing Director’s remarks, emphasising that without modern agricultural technology, efforts to expand production and improve efficiency will continue to fall short. Koim maintained that the choice facing PNG is clear: embrace mechanisation and transition to a commercially driven livestock industry, or remain constrained by subsistence practices and rising import bills. “The time for discussion is over. The time for implementation is now,” he said. The push for mechanisation aligns with national priorities to boost agriculture’s contribution to economic growth, reduce import dependency, and ensure long-term food security.

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.

PNG Air has launched a nationwide April Fool’s Day promotion combining a limited-time airfare sale with a culturally grounded giveaway under the campaign title “Pigs Can Fly.” The campaign begins with a 48-hour flash sale offering 30% off airfares across its network during a limited booking period. Alongside the fare promotion, PNG Air has announced it will award 10 pigs to individuals who participate in a social media contest by following, liking and sharing campaign content on Facebook or Instagram. Entries will be accepted until 07 April 2026. In Papua New Guinea, pigs hold significant social and economic importance. They are widely recognised as symbols of wealth, status and community connection, and play a central role in traditional ceremonies, including weddings, compensation exchanges and community celebrations. Against this backdrop, PNG Air said it aims to go beyond conventional promotions by offering something of genuine cultural relevance. PNG Air stated that the campaign was designed to balance the lighthearted nature of April Fool’s Day with a respectful acknowledgement of cultural values. “This initiative reflects both the spirit of the day and the importance of community in Papua New Guinea,” a PNG Air spokesperson said. “Pigs are an important part of cultural life, and this campaign is designed to honour that significance while capturing the attention of Papua New Guineans.” The airline also confirmed that all pigs associated with the promotion are sourced from Boroma Piggery in Port Moresby, known for producing high-quality pork. Each winner will have until the end of April to collect their pig from Boroma. The campaign forms part of PNG Air’s broader strategy to engage domestic travellers through locally relevant initiatives, while continuing to position air travel as an accessible and essential service across the country. The airfare discount is available for a limited 48-hour period. Contest winners will be announced following the close of the promotional period on 07 April 2026. For nearly four decades, PNG Air has connected the people of Papua New Guinea with safe, reliable and affordable air services. Listed on the Port Moresby Stock Exchange since 2008, the airline is majority-owned by Papua New Guinean institutions — including the MRDC Group, Pacific Balanced Fund and NasFund — and supported by approximately 2,900 local shareholders. PNG Air currently operates more than 460 flights each week across 22 destinations, providing essential passenger and cargo services that support economic development, community connectivity and national unity.

   Petroleum Resource Development Michael McWalter writes about petroleum development in its widest sense and the finding and extraction of oil and gas resources from the ground to sell them to make money, provide energy and feedstock, and the various roles and responsibilities of stakeholders and their inter-relationships. What is Petroleum Development? In broad terms, petroleum development is the overall process of finding, extracting, and refining oil and gas from the Earth, often collectively called petroleum, or otherwise hydrocarbons, though this latter term includes coal. Sometimes, we more strictly reserve the term petroleum for crude oil which derives from combining the Latin words petra meaning rock and oleum meaning oil, hence rock oil. But oil scarcely ever comes without some contained or associated gaseous hydrocarbons, which are often termed natural gas, or simply gas. Some fields contain mainly gas and just a few of what we call wetter (liquid) hydrocarbons, which we can extract from the gas such as condensate and natural gas liquids. Papua New Guinea has some oil, but considerably more gas. Figure 1: A typical black crude oil, after Wikipedia. Figure 2: Natural gas burning on a stove; natural gas is colourless, but in the right proportion with air, it will burn at high temperatures causing ionisation of the molecules and blue light emission, after Freepic. Once extracted, these substances have many uses, primarily as a source of energy, but also importantly as feedstock for the petrochemical industry. Oil and gas thus have very useful economic value, so we regard them as a resource which has a market price once they are extracted, processed and made ready and available for sale to customers. Petroleum resource development involves a complex and expensive process of exploration, drilling, discovery and appraisal, development and production, followed by the refining of the produced petroleum fluids, classically by distillation and other processes to make specification petroleum products with which we are all familiar. In the case of oil, these are typically: gasoline (petrol); kerosene; jet fuel; diesel; heating oil; solvents; lubricants; asphalt; and paraffin wax. Whilst for gas these are typically: reticulated gas; LPG (liquid petroleum gas) or bottled gas; and piped natural gas or Liquefied Natural Gas (LNG) for the long-distance transportation of natural gas. There are also other products, which we seldom see, such as heavy fuel oil, or which serve as intermediate feedstocks, such as: naphtha; ethane and propane. Figure 3: Typical products from crude oil, after Secondary Science 4 All.    It All Begins with Exploration  Exploration is an exhaustive, expensive and often high technology process. It is predicated on the essential and necessary ingredients being present that may have helped the rock strata and its contents to form gaseous and/or liquid accumulations in the subterranean rocks of the Earth. The process develops over millions of years as that organic matter contained in the rock strata under successive layers of overburden rock is transformed by heat and pressure into oil and gas. The ingredients in that process are:  an organically rich source rock which, when deeply buried and heated, generates petroleum; the movement by dint of buoyancy of that generated petroleum from the source rocks through rock strata until it is caught and trapped in a reservoir, rather than leaked to the surface; a reservoir rock that has not only sufficient porosity (space between its grains) to contain that petroleum, but adequate connection between those pore spaces to permit that petroleum to flow if tapped by a well drilled into the reservoir; a closure or trap formed by the structural configuration of the rock strata that either through folding, faulting or stratigraphic pinch-out defines a place within which petroleum may accumulate; and  a seal or containment that acts as a barrier to the upward flow of petroleum created by impermeable rocks and structures which prevents further upward movement and escape of the petroleum. Figure 4: The essential ingredients for the formation of conventional petroleum accumulations, after AAPG.  Papua New Guinea as a Petroleum Province Papua New Guinea is not short of any of these ingredients. Indeed, the geology of Papua New Guinea is quite conducive to creating accumulations of petroleum, but all the essential ingredients have to be found in the correct sequence and occur at the right time. Accumulations also have to contain significant petroleum resources that may make their exploitation worthwhile, and can deliver what we call recoverable reserves. In Papua New Guinea, we have many surface seeps of oil and gas across the country, which provide evidence of the generation of petroleum in the subsurface, and its migration and seepage to the surface in discrete places. Whilst such seepages indicate the presence of oil and gas, they also show that it is leaking to the surface. Oil and gas men look for accumulations that have been preserved intact deep in the rock strata, without such leakage, into which they may drill deep wells to tap the oil and gas in quantity, if they can find some. We have obvious and abundant folding and faulting of rocks and the right kind of rocks, both permeable and porous sandstones and limestones to serve as reservoirs, and abundant mudstones and shales to serve as sources and seals. The critical question is specifically where to look for a petroleum accumulation. Figure 5: An active gas seep of methane, ethane, propane and butane from the seabed identified during the survey of the MV Sonne, off Lihir Island, New Ireland Britain, after Brandl, P.A., Sander, S.G., Beier, C. et al. Sci Rep 15, 32389 (2025).   The Value of Petroleum  Oil and gas are not like gold. A barrel of crude oil, which is approximately 159 litres, currently (as of late February 2026) sells for about US$ 65, or PGK 278, or about US 40 cents per litre, or PGK 1.75 per litre.  A litre of crude oil is not going to make you rich, whereas a litre volume of gold would weigh a staggering 19.3 kgs (equivalent to 620 troy ounces) and be valued at an equally staggering amount of US$ 3.1 million or PGK 13.4 million at a gold price of US$ 5,000 per troy ounce. The petroleum business is a very different game to that of the gold business. A small surface seepage of natural gas or oil is scarcely of any value, and more a local curiosity.  The discovery of an accumulation of oil and gas thus has to be large and extensive to make it worthy of future development and recovery. Accordingly, oilmen select their exploration prospects, for what we term wildcat drilling, most rigorously and carefully. Wildcat drilling is high-risk exploration for oil and gas in unproven, unmapped, or abandoned areas lacking, or far from, existing oil and gas production, often without any historic discovery or prior production. Oilmen screen the geology of an area for the necessary ingredients (described above) and particularly for large geological structures that may potentially contain significant volumes of oil and/or gas, if such have indeed accumulated in their target structure. Figure 6: Oil and money, but at just US$ 65 per barrel, only large scale production can normally cover the costs of finding and extracting it.       Oil production from a field, from which say, 100 million barrels of crude oil can be recovered, might at a crude oil price of US$ 65 per barrel have a sales value of US$ 6.5 billion, but not all of that can go into the oil man’s pocket. For example, it might have taken five wells to make the discovery and a further five wells to appraise the lateral extent of the field and another thirty wells from which the oil may be recovered. These forty wells might have cost an average of US$ 25 million each, making discovery and appraisal costs about US$ 1 billion. The development of the field will require field processing facilities to clean up the oil to acceptable standards and specifications to make it fit for transportation, and likely a pipeline or set of pipelines to convey the oil to a terminal at which ocean-going oil tankers can load the crude oil for export. This may cost another US$ 1.5 billion. And then there are operating costs. To run an oil field and produce the crude oil safely, responsibly and prudently, there are daily operating expenses for manpower, machinery and materials. These may amount to US$ 100 million per year for twenty years. As you can see, the prize of finding the oil field is shrinking. And then the Government will want to ensure it is getting its agreed and defined share of its resource as the owner, typically at least 50% or more of the net value. One can see quite readily how the revenue arising from the 100 million barrels is whittled down. The oil companies might retain US$ 1 billion from this enterprise after recovering their costs, whilst the host government might make a similar amount. Naturally, each and every petroleum project has a different set of reserves, costs, and outcomes. Satisfying basic economics that the recovery of oil from the field is viable is the primary concern, and then having a firm and fair arrangement for the sharing of the net value of the produced petroleum is most desirable. Exploration and Discovery Risk The drilling of exploration wells only comes after extensive and expensive exploration surveys by geologists and geophysicists studying the rocks and their configuration at the surface and probing the subsurface with a variety of geophysical techniques. The most common geophysical technique deployed is the acquisition of seismic images of the subsurface, a bit like an ultrasound scan might be made of your stomach by a doctor, though on a vastly larger scale. Sound waves are sent into the ground, or the sea, if exploration is being conducted offshore, and the reflections from the layers of rocks are detected by a multitude of special microphones called geophones. The jumble of signals is organised and processed by elaborate computer programmes so as to create a layer-cake image of the configuration or structure of the subsurface rock strata. Knowing the velocity of sound through the rocks, the geophysicists can interpret these images of the subsurface and make depth maps of potential trapping structures. It is a tedious and expensive process which is not at all easy in the jungle-wrapped, mountainous and often swampy terrains of much of Papua New Guinea. Combined with surface geological descriptions of the visible outcrops of rocks and their faulting and folding, the petroleum geologist will attempt to define leads and prospects which may be promoted for wildcat drilling. Already in this process, tens of millions of dollars will have been spent on physical surveys, data processing and geophysical and geological interpretation. Figure 7:  A seismic reflection image of part of the Gulf of Papua called the Flinders Basin showing the underlying subtle faulting and folding of the strata, after PNG Chamber of Mines and Petroleum.    The company then has to evaluate its portfolio of prospects, both within the country in which it is exploring and globally, and make a choice as to which prospects in which countries it will prioritise and commit to drilling. It does this on a risked basis and then applies the economics of the applicable national petroleum regimes to make an assessment as to whether it might be possible to make money. It is always a risky business, akin to making an expensive movie, which may be a success or a failure. Some liken it to gambling in a casino, because of the intrinsic uncertainty of the subsurface geological history. However, oil and gas companies shrewdly assess all the risks involved. Drilling the Ultimate Gamble There are fundamental geological risks as to whether an accumulation of petroleum may be present within a prospect. Alas, the only way to find out whether a prospect contains oil and/or gas is to drill the prospect. The chance of discovering oil and gas depends much on the type of well, with success rates for wildcat exploration wells typically ranging from 10–20% in new frontier areas to a global average of between 30–40%. Approximately 60–70% of initial exploration wells fail to find accumulations with quantities adequate for commercial development and production. In known petroliferous areas and where development drilling is taking place near to or on known accumulations, the success rate can be as high as 80% to 90%. Those petroleum provinces in well-established producing nations thus present much less risk than hitherto undrilled provinces where little or no drilling has previously taken place. Figure 8: A drilling rig in the Highlands of Papua New Guinea, after PNG Business News.    The risk of discovery is skewed by perceptions of the host nation’s petroleum endowment, and so the host Government necessarily has to adjust its terms and conditions of petroleum development up or down depending on the likelihood of discovery. Drilling a wildcat well in the Seychelles, where only four wells have previously been drilled without success**,** is a very different game from drilling a wildcat well in Libya**,** where more than 1,500 wells have been drilled over the last 70 years with more than 500 oil and gas discoveries. Hence, the Government of the Seychelles might have to offer the most attractive terms to encourage the international oil and gas companies to explore in its territory rather than in other perhaps more petroliferous places. In Papua New Guinea, the total number of real wildcat wells is less than 275 spread out over the last hundred years. The Wohumul boreholes were drilled in the Oriomo River area of the Western Province, near Daru in 1925; these were shallow tests. The first deep well in Papua New Guinea was drilled at Kariava-1 in the Gulf Province. Interestingly, this well was spudded on 8th March 1941, suspended in 1942 due to World War II**,** and resumed drilling in 1946 before being abandoned in 1948. Exploration for oil in Papua New Guinea is not a new game; it has taken place for decades with tantalising results that have taunted many an oilman. It was only in 1986 that significant success was obtained at the Iagifu 2-X well when Niugini Gulf Oil, which became part of the Chevron Corporation as Chevron Niugini, found a significant accumulation of black oil near Lake Kutubu**,** which gave rise to the Kutubu Petroleum Development Project in 1990. Hitherto, nothing of commercial significance had been found and no development or production of oil and gas had been commercially undertaken. To date, Papua New Guinea has discovered oil and gas in dozens of prospects**,** at least half of which have been made the subject of development and production operations recovering both crude oil and natural gas in commercial quantities. Figure 9: Oil and Gas Reserves of Papua New Guinea, after Manau, August 2021 modified.      Factors Affecting Petroleum Development Finding an accumulation of oil and/or gas is a great feeling for the oilman, but unless the volume of the accumulation is large enough to be commercially exploited by development and production operations, it cannot recompense the company for the considerable expense of finding it. The cost of drilling a well very much depends on its location and its distance from supply chains and support facilities. Papua New Guinea remains a remote place for petroleum development operations of all kinds, being far from major petroleum development hubs. Much of Papua New Guinea remains a frontier petroleum province, notwithstanding 34 years of crude oil production and 12 years of gas production and LNG export. Put quite simply, Papua New Guinea is not Texas, where over 1.5 million wells have been drilled and between 157,000 and 187,000 wells are active. The presence of abundant civil and petroleum infrastructure in Texas makes the cost of petroleum development vastly lower. While high-production wells currently dominate production, thousands of older, "stripper" wells across Texas produce less than 10–15 barrels per day – not an unreasonable income if privately owned and the crude oil is able to reach the market readily through a convenient nearby pipeline. It is a very different story in Papua New Guinea, in which civil infrastructure is scarce and petroleum infrastructure is project-specific and sparse. A frontier province is an unexplored or underexplored geological region with suspected, but unproven, significant petroleum resource potential. Such is the case of the deep waters of the Coral Sea where TotalEnergies and Petronas plan to drill the Mailu-1 deepwater well soon, targeting Eocene carbonate reservoirs. Such a deepwater well is likely to cost about US$ 100 million for an estimated drilling period of less than two months. Such risks are not for the faint-hearted. It has been said that the drilling of absolutely rank wildcat wells in a petroleum basin where no prior exploratory drilling has taken place is indeed a bit like going into a casino for the first time, but bypassing the slot machines and going straight to the high-stakes tables! Of course, whether a sedimentary basin holds petroleum accumulations or has even generated oil and gas is not always certain. Sometimes subsurface conditions are not correct, or in the right order. Sometimes, there is no sign of any oil or gas seeping to the surface. It can be very much a blind gamble. But once a discovery is made in a newly explored basin, most often the herd of oil and gas companies come charging in. Getting that critical breakthrough of the first discovery is very important, not only for the exploring company which is investing in that exploration effort, but also for the host government which wishes to elucidate its petroleum prospectivity fully. Figure 10: The steps of petroleum resource development, after Valerie Marcel.  The Government Role Many governments around the world shy away from all but the very basic pursuits of oil and gas exploration because of the considerable expense and enormous risks.  They may obtain some seismic reflection surveys, particularly in offshore areas, either though bilateral aid and/or by speculative surveys conducted by seismic survey contractors who will pay for the survey and then promote the resultant data and provide a royalty or profit share to the government.  This may initiate exploration interest from established oil and gas companies and, of course, scientific interest from academia which will now have new knowledge about the geological subsurface arising from those surveys.   Governments typically offer their unexplored areas for exploration by competent oil and gas companies either by the grant of licenses or contracts.  That competency is not just technical, but includes corporate, environmental, financial, safety and social capacities; all are required at some stage during the cycle of petroleum development.  It is for these strengths that host governments tend to engage the international oil and gas companies; they know what they are doing.  But equally important, the host government needs to hold them strictly to account, most assiduously, and if deficiencies emerge, sanctions and penalties should be applied. A host government needs to rise to the challenge of the companies that it engages through licences or contract by having a highly competent petroleum regulatory organisation of its own, the staff of which should be very well rewarded for being guardians of the treasure of the nation’s oil and gas resources. Government objectives are primarily monetary; to translate the value of its petroleum resources into revenue which can then be used for the national development agenda. But equally, governments do not like to be kept in the dark, so quite often they participate, not in exploration, but in development and production by taking a stake in the petroleum project. Papua New Guinea has a legal option to participate up to 22.5% all petroleum projects.  This brings valuable inside knowledge of the development to the host government, and further revenue. There are other aspects of a petroleum development though, which need to be fostered.  For many nations, a critical issue is the security of supply of oil and gas to the economy. For all nations, keeping as much of the business within the country is an important issue, making sure local people are employed and contracted, and local business are contracted for goods and services as far as is possible.  This should not just be a political wish, but a coordinated effort by company and government alike to do what is possible, and assess what may be feasible with incentives and capacity building.  Figure 11:  Fabrication at a local engineering firm in Nigeria, after Jarander.   The investing companies normally meet the costs of basic exploration and are required to culminate their exploration programmes by selecting prospects where petroleum accumulations may have been formed, and then drilling them to test whether there are indeed any.  These agreed exploration programmes are the work commitment of the companies to their host government. Failure to undertake and complete the work typically results in cancellation of the licence or contract.  Sometimes, the company simply quits for one reason or another. They may simply not be successful in finding structures eligible for the considerable expense of drilling. There may be inadequate evidence of the potential for an accumulation, or there may be better prospects in other areas which the company is exploring, either in the same country, or elsewhere.  The oil and gas company will maintain a portfolio of exploration areas around the world and seek to optimise overall exploration risk and invest in drilling its best prospects.    If a company cannot fulfil its work programme, it normally has to depart and surrender the area back to the government, sometimes with penalties. This enables the host government to give the area to another company, which may have different ideas, theories, understanding and appetite for the petroleum geology of the area.  What governments hate is when companies sit on a prospective area without doing any work, hoping that the holders of adjacent areas will have success in discovering oil and gas and so elevate the value of their area. This is pure speculation and should be discouraged; it defies the intent of the government in granting the licence or contract in the first place for valid exploration work to be done. Of course, when a new petroleum province opens up after a discovery has been made, the herd mentality of the oil and gas industry is such that everyone rushes in to try to get a slice of the action.  This enthusiasm borne out of discovery needs to be captivated by the host government and it should be used to entice more exploration investment. Naturally, the best indication of the likelihood of the discovery of further oil and gas accumulations is an adjacent discovery; it certainly boosts the prospectivity of nearby areas. So governments need to be agile in their thinking and promotion of their petroleum resources for development.    Petroleum Rights    Apart from private lands in the USA, almost all petroleum rights around the world are held by the host sovereign government.  The USA is the odd one out; it has tied subsurface mineral rights to surface rights in private lands, though it retains control and ownership on Federal lands and offshore. Thus, across the world the government is normally the owner of the petroleum as it exists in the ground. In using the prowess and capabilities of the oil and gas companies to explore, the host government has to make sure it is rewarded as the guardian of the oil and gas resources that may lie in its territory. The oil and gas companies foot the bill for exploration, but if they are unsuccessful, they go home empty-handed. After the initial discovery of recoverable black oil at Kutubu in 1986, droves of oil and gas companies took up areas for exploration in Papua New Guinea, but only a few had success. Amongst those that came to Papua New Guinea, but left empty handed were: Conoco, Shell, Phillips, Pennzoil, Statoil, Mobil, Amoco, Marathon, Petrofina, Santos, Woodside, Union Texas Petroleum, and many a smaller company.   Some came and were successful in one area, but not in others. Some sold out their share of discoveries before development activities commenced, not having the commitment, will or ability to stay though development to production. Some departed, came back, departed and came back again; one could say that such companies were quite flexible and mobile in their thinking!   It is important to remember that the rights to conduct petroleum operations are typically exclusive over a defined area or tenement and finite in term after which they expire.    Figure 12:  A map of petroleum tenements in Papua New Guinea circa late 2025, after the National Petroleum Authority.  The Petroleum Regime   Petroleum rights are licensed or contracted out to competent companies by a host government under defined term and conditions normally articulated in law, regulations, contracts and licences. Alas, the real substance of these terms and condition only comes into effect after discovery. If the companies are successful and find accumulations that are worthy of commercial extraction, they are subject to regimes in which they share a substantial proportion of that value with the host government. Petroleum regimes are a fundamental exercise of the sovereignty of a nation over its petroleum resources that may have value if they are recovered in quantity as recoverable reserves. Oil and gas in the ground have little value if they cannot be recovered to the surface and sold for value. It is upon this extracted value that petroleum regimes are assessed and implemented.  There are many different methods for the host government to extract value: by the charge of rents, royalties, levies, bonuses, duties, and fees; taxation on income; taxation of employees; withholding taxes on interest payments and dividends; the take-up of equity by the government in a project for the production of oil and gas; the sharing of petroleum production; domestic supply obligations at discounted prices; and local content provisions. These provisions are normally established by law, contract, agreements and/or licence conditions prior to the commencement of exploration activity and most certainly before production operations commence to provide certainty to both the investing oil and gas companies and the host government.  Such fiscal design should attempt to cover all likely scenarios, but often precedence and political emotions distort clear thinking. Figure 13:  Fiscal design can be quite daunting, after Dan Johnston. The broad objectives of a petroleum regime are to reduce uncertainty; present a clear picture of the applicable commercial and tax terms, limit negotiations on tax issues, provide fair and equitable tax treatment for all investors, avoid double taxation and assure that the international oil and gas companies can obtain home country foreign tax credits for taxes paid overseas.  The general rule seems to be that the more attractive the resource base is, the tougher the fiscal and commercial terms of the host Government tend to be.  Of course, many other factors come into play, not the least of which is the remoteness of the place.    Take for example the Falkland Islands where despite discovering oil in 2010, the companies only made a final investment decision for the Rockhopper oil field in late 2025 with first oil planned for 2028.  Its remoteness from supply chains of any kind, let alone oil field supply chains and concerns about the Falklands ability to remain unaffected by Argentinian claims prolonged the progress towards field development.  Papua New Guinea suffers from a similar remoteness, with Singapore and certain bases in Australia being the nearest supply depots for oil and gas operations. Also, there is inadequate petroleum exploration to keep drilling rigs and other oilfield exploration equipment permanently busy and stationed in Papua New Guinea, necessitating their importation repeatedly and sporadically for isolated exploration campaigns.     Access to Land   Papua New Guinea also remains very much an under-tested frontier oil and gas province with comparatively low exploration density, but with reasonable success in locating oil and gas accumulations.  It is still attractive for exploration due to having significant and demonstrable oil and gas generation.  Other specific factors come into play as they do anywhere.  In Papua New Guinea, adherence to customary land tenure means that even though the State asserts its ownership rights of oil and gas in the subsurface, both the oil and gas companies and the State have to gain access to exploration areas, by dealing with the local landowners and entering onto their land. Their title to their land is undocumented, unalienable and enduring, and the companies and State have to treat with the landowners most carefully.  Figure 14: Landowners look on outside a petroleum operations camp, after Celine Rouzet. The hopes and expectations of landowners are heightened as and when oil and gas are found on their land, as might be expected anywhere. If the discovery is large enough to warrant development and subsequent production, quite clearly the customary landowners will be affected.  In Papua New Guinea unlike more despotic places, where landowners might be forcibly removed and shunned away, there are legally defined provisions by which the landowners may share in the process and benefits of petroleum development. Even at the exploration stage, the oil and gas companies are strictly required to pay compensation for their entry on or occupation of the land. Moreover, the companies have to undertake social mapping and landowner identification studies to ensure that they are dealing with the correct people.  By law, neither party is to interfere with the rights of the other. The companies have the right by law to enter and occupy land reasonably required, but without interfering with the existing use to any greater extent than necessary, and they may not interfere with fishing or navigation. Landowners for their part, may not enter on, occupy or interfere with any land being used for petroleum operations. These are as much responsibilities as rights for each party.             When development commences, the companies are encouraged to use as much local labour and content as possible. The Government typically provides the local community with business development grants to help the landowners participate.  Whilst National Content has been rightly emblazoned in Papua New Guinea Government policy in recent years, there have been provisions in the Oil and Gas Act, 1998 for domestic procurement obligations upon the companies for almost three decades. These require the use and purchase of goods and services supplied, produced or manufactured in Papua New Guinea whenever the same can be obtained at equivalent terms; encouraging and assisting citizens who are desirous of establishing businesses providing goods and services; and making maximum use of Papua New Guinea contractors and subcontractors. Alas, little emphasis has been made on enforcing this, let alone making regulations to give effect to the provisions or even examining compliance by companies.      Additionally, the Oil and Gas Act specifically defines benefits for the landowners and also for the affected Local Level Governments and the Provincial Governments when petroleum development proceeds to production of oil and gas.  These variously comprise: royalty benefit; equity benefit; development levy; other project benefits; and project grants. Whilst the Act generically specifies beneficiaries, these grants and benefits still need to be shared out and it is for this that the Act requires the Government to hold a development forum to which representatives are invited from all community stakeholders. This is an excellent, though exhaustive process, but one that far exceeds the treatment of people in petroleum areas in many other nations.  Papua New Guinea should be proud of this legally enshrined sharing and consultative process and it should be implemented with utmost care and concern.   Changes to the petroleum regime or simple uncertainty of its application may also bring added risk for exploration and development. Obviously, all governments wish to optimise the value that they can garner from petroleum resource development; after all it is their resource – to be used for the benefit of all in the Nation. Striking the best terms with the oil and gas companies, whilst enabling those same companies to make a reasonable return on their investments, is often a delicate balance. Sometimes, that balance cannot be achieved, and therefore exploration is thwarted or development of the discovered petroleum resources cannot be pursued. Proposed projects cannot proceed if there is imbalance between the company and government requirements; both parties need to win.  However, all decisions for development are predicated on awkward and uncertain assumptions about the future business of petroleum production.   Production Risks    Production profiles may be defined based on rigorous assessment of the amount of oil and gas that may be recovered from an accumulation.  Well tests are performed to gauge how reservoirs will behave and how much oil and gas a given well can produce. Test results are aggregated and a field development plan with a production profile is prepared based on tapping the oil and gas accumulation with a specific number of development wells. If enough appraisal drilling and sound geological assessment has been made of the reservoir and the physical parameters of the accumulation, a prediction may be made of the extent of recovery of the oil and gas from the accumulation.  Alas, only a fraction of the oil and gas originally-in-place can be recovered. Recovery factors vary from field to field and the nature of the oil and gas and the manner of how the field will deplete over time.  Sometimes, fields perform better during production, and sometimes they fail to live up to expectations.  The potential outcomes have to be risk-managed. Whilst petroleum engineers and geologists may attempt to limit such risk, it always exists. One only knows exactly how much oil and gas one can get out of a given oil and gas field on the last day of economic production when the value of the oil and gas which that field produces fails to covers the ongoing costs of its extraction. However, these risks pale into insignificance if one cannot get oil and gas production to market as result of exogenous risk, such as the closure of vital shipping lanes, like the Strait of Molucca between Indonesia and Malaysia, or the Strait of Hormuz between Iran and the United Arab Emirates and Oman through which 20% of the world’s global oil supply moves.  Figure 15: Whilst many production risks may be managed, exogenous risks such as the closure of major shipping routes may cut off petroleum producers from their markets, after freeworldmaps.net.  Price Risks    The economic outcome of production is determined by the volume of oil and gas produced by its sale price per unit of production. That depends on the quality of the oil and gas and the global market price for oil and gas of that quality. Gas is normally sold with reference to the crude oil price.  Importantly, that sales price for the oil and gas is only after it has been has been appropriately processed into saleable and transportable streams.  The oil has to be separated from water, sediment, and gaseous components, and likewise the gas has to be conditioned to specifications by the removal of water, noxious impurities like carbon, nitrogen and sulphur oxides, and natural gas liquids which can be sold separately. This all costs money to enable the produced oil and gas to be transported safely by pipelines and ships, and delivered to customers for downstream processing and supply. ,   The price of oil is, as we commonly know, subject to much fluctuation depending on global markets which are affected by many factors. Fundamentals such as global supply and demand predominate often highly influenced by politics and international relations, and nowadays, to a smaller degree, by energy transition policies. In so far as oil and gas revenues are thus variable, the projected income of any given oil and gas project is consequently variable. In embarking on an oil and gas development project, the investing oil and gas companies have to accommodate the risk of falling commodity prices and hence revenues, just as much as they have to consider the opposite with higher commodity prices. A development project has to weather the vagaries of the oil and gas prices as they occur.  Equally, as most oil and gas projects extend for decades, they have to countenance changing economic conditions, such as inflation and the cost of money as represented by the discount rate. Figure 16: Crude oil prices 1976 to 2026 with volatility somewhat suppressed due to use of a logarithmic price scale, after CrudeFacts. These extraneous matters often swamp the potential and forecast technical outcomes. Oil and gas price behaviour and the value of money throughout the life of a petroleum development project are key factors for both the investing company and the host Government alike.  No matter what petroleum arrangements and regime are used there needs to be an agreed understanding of the effect of swings in price and the value of money, lest either party is unduly penalised during the project life.  Most often the petroleum regime, one way or another, has a built-in ability to adjust the sharing of the net value of oil and gas production after the costs of exploration, development and production. For instance, income tax is only charged on net income or profit, so if oil and gas prices decline, profits decline and taxation accordingly also declines. In production sharing arrangements, the sharing of production comes only after the companies receive cost recovery payments, so a company’s share is reduced (as is the Government’s share) when prices are low. There can be elaborate fiscal adjustments made both for the upside and downside of production operations. Royalty and such direct levies can be made scalable. Capital depreciations for allowances against taxation income can also be adjusted, both up and down. Windfall taxes, additional production shares, or additional profits taxes can be triggered at times of elevated prices.  The key is for each party – both company and Government alike to respect the durability of the petroleum project and accommodate the volatility of prices by respecting the needs of the other party.   Other Development Criteria    When preparing a petroleum project for the production of oil and gas from a field, many matters have to be considered. Not only do the fiscal and commercial arrangements with the host government have to be firmly agreed and be robust for all likely outcomes, but environmental protection and the welfare of the community in which the project may be developed are required. There are necessary social and environmental impacts of petroleum development, but they can be minimised and mitigated by good practice.  Whilst exploration and appraisal costs are normally funded out of the company’s own money – its equity, when it comes to development, the extreme costs most often necessitate recourse to the borrowing of funds from financial institutions. Not all banks are willing to finance oil and gas developments these days due to the degradation of the Earth’s atmosphere caused by the emission of carbon dioxide on combustion of oil and gas and the subsequent effect of global warming of the atmosphere by the greenhouse effect.  Alas, many of those banks that withhold their financing are resident in nations in which their industries have been the primary polluters of the atmosphere for decades. Having initiated global warming and developed their economies, they now seek less developed nations to curb their emissions. This seems to be quite unfair. Fortunately, there are financial institutions that are more pragmatic and realise that there is no single big switch in energy supply to curtail all oil and gas production and usage.  Oil and gas will be essential ingredients in the global energy mix for decades to come, unless we wish energy poverty to pervade the planet, and life as we know it to be halted. This is not to support a case against global warming which is a documented scientific fact. We all have to be considerate of the future of our planet and work carefully towards limiting emissions of carbon dioxide and so limiting the extent of global warming through appropriate policies and investment in non-polluting energy of which renewables are just part of the mix alongside improved nuclear technology.   The Final Investment Decision   Once all aspects of a specific petroleum development project have been organised and prepared, the project plans may be presented to the host government for approval. Naturally, being a predominantly interested party, the host government normally readily approves these plans. After all it will be looking forward to its share of the earnings and other benefits from the proposed project.   Once the development licence is granted or a production permit is approved pursuant to a production sharing contract, the company (most often a consortium) has to make its final investment decision which triggers development operations. Various measures are used to determine the acceptability of a project for investment, traditionally the internal rate of return was used. It measures the effective rate of return earned by an investment as though the money had been lent at that rate. Alternatively, and used much more these days, is the net present value of a project which measures the capital created over and above the company’s investment hurdle rate.      Figure 17:  The Decision Rule, after Allen and Seba. This decision is not one made by the host government, but by the investing company, but failure to proceed with development may incur severe penalties once host government approval has been given. Most often the investing company is required to provide the host government with a corporate guarantee of value equivalent to the intended investment as part of its application for development approval.  That way the Government is not misled into approving a fake development where nothing happens, and allowing the company to slip away without repercussions.  When Chevron Niugini led the Kutubu Petroleum Development Project in 1990, Chevron Corporation, its parent company, provided an irrevocable letter of guarantee to the Independent State of Papua New Guinea to the value of its share of the expense in the project on its corporate letterhead signed by the President of Chevron Corporation; it was as good as gold! But they never hesitated in their development intent and resolutely developed the Kutubu fields as professionally as they could.     Michael McWalter is a former Director, Petroleum Division and Adviser to the Government of Papua New Guinea, and erstwhile petroleum adviser to the Governments of Ghana, Liberia, Cambodia, Sao Tome, and South Sudan. He is certified petroleum geologist and technical specialist in upstream petroleum industry regulation, administration, and institutional development.   Caption    

Westpac is making a significant investment in strengthening leadership capability across its Pacific businesses with the rollout of its best-in-class LEAD program in Papua New Guinea and Fiji this year, delivering training to 120 employees across the two markets. LEAD is Westpac Group’s flagship leadership development program focused on building future-ready leaders through experiential learning, coaching, and strategic capability uplift. The LEAD program is designed to build practical leadership capability, equipping participants with the skills, confidence, and mindset required to lead teams, support customers, and contribute to Westpac’s long-term success in the Pacific. The program will be delivered through in-person training sessions supported by online modules, ensuring the learning is relevant, grounded in local context, and immediately applicable in day-to-day roles. By delivering the program locally, Westpac is enabling participants to learn alongside peers, strengthen networks across the business, and apply leadership learning directly within their teams and communities. The world-class format also supports deeper engagement, discussion, and reflection, reinforcing Westpac’s commitment to investing in meaningful, high-quality development experiences for its people. The program covers: • Leading Self – building self-awareness, confidence, and personal leadership effectiveness • Leading Others – developing strong people leadership, communication, and coaching skills • Strategic Thinking – strengthening decision-making and broader business understanding • Leading Change – equipping leaders to navigate change and lead with agility • Customer & Outcome Focus – linking leadership behaviors to customer and business outcomes • Pacific Context Application – applying leadership skills in real-world PNG and Fiji settings Maria Stefanac, Head of People, Pacific, said the LEAD program represents a significant investment in Westpac’s Pacific workforce. “LEAD is a major investment in our people in Papua New Guinea and Fiji. We know that strong leadership is critical to creating a positive culture, delivering for our customers, and building a sustainable business for the future,” Ms. Stefanac said. “This program has been designed to support our people to grow as leaders, build confidence in leading others, and develop skills they can apply immediately in their roles. By having Westpac Group trainers deliver the program here in the Pacific, we’re ensuring our leaders benefit from global expertise while learning in a way that is relevant, practical, and grounded in local context.” Ms. Stefanac said the program also reflects Westpac’s broader commitment to developing talent from within and creating clear pathways for growth and progression. “Investing in leadership capability is an investment in our future. Through LEAD, we are supporting our people to step into leadership roles, strengthen their impact, and continue to serve our customers and communities with confidence.” Westpac Banking Corporation ABN 33 007 457 141. The liability of its members is limited. Westpac is represented in Papua New Guinea by Westpac Bank - PNG - Limited. The LEAD program forms part of Westpac’s ongoing focus on capability building and people development across the Pacific, recognizing that empowered, well-supported leaders play a critical role in driving strong performance, engagement, and customer outcomes. By continuing to invest in programs such as LEAD, Westpac is reinforcing its long-term commitment to its people in Papua New Guinea and Fiji and to building leadership capability that supports sustainable growth across the region.

Papua New Guinea’s public and private sectors paused on March 24 to mark National Women’s Day, with workplaces, institutions and communities across the country embracing the symbolic colour purple and reaffirming their commitment to advancing the rights and wellbeing of women. From corporate offices to government agencies, the day was observed through awareness programmes, advocacy events and public gatherings, reflecting a growing national movement to prioritise gender equality and women’s empowerment as a central pillar of development. In Port Moresby, the National Capital District Commission (NCDC), through its Family, Gender Equality and Women’s Empowerment Branch, hosted a major celebration at Sir Hubert Murray Stadium under the theme “Strongim Meri, Protectim Rights, Buildim PNG.” The event drew participation from women leaders, government representatives, civil society organisations and the private sector. NCD Governor Powes Parkop used the occasion to outline an ambitious long-term vision for women’s empowerment under the national government’s “Reset 50” agenda, which sets the direction for the country’s next 50 years of nationhood. Governor Parkop, who also chairs the Permanent Parliamentary Committee on Gender Equality and Women’s Empowerment, stressed that gender equity must be treated as a non-negotiable national priority. “We must empower and recognise the National Council of Women as vital stakeholders in lifting the status of women over the next five decades,” he said. He highlighted several key policy and funding commitments already underway, including the National Strategy to Prevent and Respond to Gender-Based Violence (2025–2036), a government allocation of K108 million annually over the next decade to combat GBV, and the adoption of the National Gender Equality and Women’s Empowerment Policy (2025–2036). He also confirmed the formal decision to revive and reinstate the National Council of Women. Despite these milestones, Governor Parkop cautioned against complacency, urging women leaders and stakeholders to ensure that policies translate into tangible outcomes. “Policy adoption is only the first step. We must ensure sustained attention, adequate resources and consistent effort in implementation,” he said. Deputy City Manager for Community and Social Services Ms Edith Laufa echoed these sentiments, thanking Governor Parkop for his leadership and advocacy at the national level. Drawing from her own experience in a male-dominated work environment, Ms Laufa encouraged young women to pursue their ambitions with resilience and confidence. “Approach your work with dedication and determination. Your leadership can inspire others and help break barriers,” she said. Beyond government-led initiatives, the private sector also played a significant role in marking the day. Financial services company MoniPlus hosted a cancer awareness session in partnership with the Papua New Guinea Cancer Foundation, aligning its internal observance with International Women’s Day themes of health and wellbeing. The session focused on breast cancer awareness, highlighting the importance of early detection, screening and prevention. Medical Health Educator Dr Beena Dagam of Port Moresby General Hospital volunteered her expertise to deliver the session, reinforcing the critical role of education in reducing cancer risks. “Conversations like this are important. They inform us about the factors that put us at risk and empower us to take early action,” organisers said. The programme also emphasised that cancer risks are not only linked to lifestyle factors but may also stem from inherited genetic mutations, underscoring the importance of vigilance and regular health checks. In Tok Pisin, the message of prevention was clearly communicated: “Save gut pas long as blo sik kensa long abrusim bipo yu kisim,” highlighting the need for prevention, early detection and screening. As Papua New Guinea continues to navigate its development pathway, this year’s National Women’s Day served as both a celebration and a call to action, reinforcing that empowering women is not only a social imperative but also a critical driver of economic growth, community wellbeing and national progress. Across the country, the message was clear: building a stronger PNG requires sustained investment in women—protecting their rights, amplifying their voices, and ensuring equal opportunities for generations to come.