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Papua New Guinea and Solomon Islands are seeking to deepen economic cooperation, increase cross-border investment and develop stronger business-to-business partnerships as the two Melanesian neighbours work to translate longstanding political ties into economic gains. PNG Prime Minister James Marape made the call during the inaugural Papua New Guinea-Solomon Islands Business Investment Forum in Honiara, held under the theme “From Opportunity to Investment: Building the PNG-Solomon Islands Growth Corridor.” The forum brought together government leaders, investors, business executives, financial institutions and private-sector representatives from both countries. Marape said the forum should mark the beginning of sustained economic engagement between the two countries, with a focus on investment, trade, employment, downstream processing and greater economic independence. “What good is political independence without economic independence?” Marape said, calling for both countries to build economies strong enough to stand on their own feet. He said PNG and Solomon Islands were permanent neighbours whose economic interests were closely linked by geography, culture and history. “We must construct a future that is fair and balanced, respects our people and our businesses, and allows us to walk step by step, side by side, into the future,” he said. The forum followed Solomon Islands Prime Minister Matthew Wale’s official visit to Port Moresby in June, during which the two countries signed the Framework Agreement on Development and Economic Cooperation 2026-2030. The agreement provides a framework for cooperation in trade and investment, mining, fisheries, agriculture, infrastructure and other areas of mutual economic interest. Marape said the Honiara forum was intended to translate that government-level commitment into private-sector projects and partnerships. “When Prime Minister Wale visited Port Moresby, we agreed that our relationship must produce tangible outcomes for our countries,” he said. “We have established the government framework. Now we want our private sectors to identify projects, establish partnerships and turn those opportunities into investment.” PNG investment presence PNG already has a significant commercial presence in Solomon Islands. A 30-year review records 126 PNG-origin registered investments across 18 sectors, including agriculture, communications and information technology, construction, financial services, fisheries, mining, insurance, professional services, retail and wholesale, tourism and transportation. The investments have proposed employment for more than 7,500 Solomon Islands citizens, with agriculture, professional services and fisheries among the largest employment-generating sectors. Marape said PNG businesses had demonstrated that they could invest successfully beyond the country’s borders while creating jobs and contributing to a neighbouring economy. “Papua New Guinean businesses have demonstrated that they can successfully invest beyond our borders while creating employment and contributing to the economy of a neighbouring Pacific country,” he said. He encouraged Solomon Islands businesses to similarly explore opportunities in PNG. Joint investment opportunities Marape said the two countries had opportunities to cooperate in mining, fisheries, agriculture, energy, tourism, infrastructure, financial services, telecommunications, transport and downstream processing. He particularly highlighted opportunities for joint ventures and partnerships between businesses in both countries. “If we can source capacity from each other, let us source it. If we can have joint ventures amongst each other, let us have those joint ventures,” he said. PNG businesses already operating in Solomon Islands include companies in property, finance, retail, fisheries, professional services, construction and other sectors. Marape encouraged PNG businesses operating in Solomon Islands to develop local partnerships and support the growth of Solomon Islands-owned small and medium-sized enterprises. “PNG businesses, as you work here, incubate a local business to be your value partner,” he said. “A good relationship, a good business venture and a good reputation is premium capital.” Mining, fisheries opportunities The two countries’ marine resources represent another potential area for cooperation, Marape said, particularly in fisheries. PNG and Solomon Islands have large exclusive economic zones with significant tuna resources. Marape called for greater domestic processing and manufacturing rather than simply harvesting and exporting fish. “We have been open for business for so long. We now want to go into partnership,” he said. “We want to step up processing of our catches in our respective countries.” He said stronger cooperation could help the two countries build regional value chains for tuna and other marine products while creating employment and retaining more economic value domestically. Marape also encouraged responsible investment in mining and energy, saying investors should receive reasonable returns while host countries, landowners and local businesses benefit through taxation, royalties, equity and local content. In a separate bilateral meeting with Wale at the Heritage Park Hotel, Marape said Solomon Islands had again invited PNG investors to participate in its economy. He said more than K1 billion of PNG investment was already present in Solomon Islands, with more than 59 PNG companies of various sizes operating there. “We already have over K1 billion worth of Papua New Guinea investments in Solomon Islands, with more than 59 PNG companies of different sizes operating here,” Marape said. He said the two countries could also explore joint participation in major mining projects, including arrangements that would ensure Solomon Islanders remained the principal beneficiaries of their natural resources. Marape said PNG was prepared to consider equity structures in which Solomon Islands government entities, companies, provincial governments and landowners retained majority interests, while PNG companies contributed capital, expertise and experience. “We are not coming here simply to take resources out. We want genuine partnerships in which Solomon Islanders remain beneficiaries of their own resources while our companies contribute capital, expertise and experience,” he said. Economic relationship The leaders also discussed trade and investment, border arrangements, mining, fisheries, agriculture, education, policing and security, air connectivity and other areas of bilateral cooperation. Marape said the direct air connection between Honiara and Port Moresby would help facilitate the movement of businesses, investors and people between the two countries. He said both governments needed to ensure that bilateral agreements translated into practical economic outcomes. “Our political relationship is strong, our cultural and historical relationship is permanent, and now we must build the economic relationship to the same level,” Marape said. “A stronger PNG-Solomon Islands economic corridor will strengthen both countries and contribute to a more economically resilient Melanesia and Pacific,” he said. Marape said PNG’s economic diplomacy should also encourage domestic companies to expand internationally, rather than focusing solely on attracting foreign investment into the country. “Papua New Guinea must also become an investor in the Pacific and, increasingly, beyond our region,” he said. He identified banks, telecommunications companies, resource businesses, superannuation funds, agricultural companies, professional firms and SMEs as potential regional investors. The prime minister said stronger economic integration between PNG and Solomon Islands could serve as a model for wider Melanesian and Pacific economic cooperation. “A healthy Solomon Islands is a healthy PNG. A healthy PNG is a healthy Solomon Islands,” Marape said. “Our strength is in economic prosperity.” He urged businesses attending the forum to focus on practical opportunities, identify projects and establish joint ventures as the two countries seek to build a stronger economic relationship over the coming years.

Great Pacific Gold Corp. has expanded the interpreted footprint of two high-grade gold vein systems at its Wild Dog Project in East New Britain following new mapping and channel-sampling results. The company said its latest work at the Elamaraka and Kargalio vein systems had identified additional mineralized quartz-sulphide veins beyond historically mapped areas, strengthening the potential of the southern Wild Dog structural corridor. At Elamaraka, continuous channel sampling returned 9 meters grading 4.81 grams per tonne of gold, 41.96 grams per tonne of silver and 0.02% copper. Individual samples included grades of up to 26.86 grams per tonne of gold and 233.4 grams per tonne of silver. Additional vein exposures along the interpreted corridor returned 4.22 grams per tonne of gold from a grab sample, while channel samples returned 1.20 grams per tonne and 1.05 grams per tonne of gold. Great Pacific Gold said mapping indicated Elamaraka was broader than a single historical vein, with multiple quartz-sulphide veins showing similar structural orientation and mineralization styles. The Elamaraka system is about 2 kilometers southwest of the Sinivit deposit and forms part of the southern continuation of the Sinivit-Kavasuki epithermal corridor. At Kargalio, a 6-meter channel interval returned an average grade of 7.29 grams per tonne of gold, 12.83 grams per tonne of silver and 0.24% copper, including 2 meters at 16.20 grams per tonne of gold. A second 6-meter channel interval about 40 meters south returned 2.85 grams per tonne of gold, 8.20 grams per tonne of silver and 0.15% copper. Another quartz-sulphide-clay breccia zone about 260 meters east of the Kargalio vein returned about 10 meters at 1.77 grams per tonne of gold. The company said mapping had identified additional mineralized structures at Kargalio, supporting its interpretation that the prospect represents a broader mineralized corridor rather than a single historical vein. Great Pacific Gold Chief Operating Officer and Vice President Exploration Callum Spink said the results had strengthened the company’s understanding of the southern Wild Dog corridor. “Historical work reported high-grade gold mineralization at the EK Target Area. Our recent mapping and systematic sampling indicate that these prospects form part of broader mineralized corridors containing multiple quartz-sulphide veins,” Spink said. The company has also begun work in the South Zone of the 15-kilometer Wild Dog structural corridor, with earthmoving equipment clearing an access track south of Elamaraka and Kargalio. An exploration team has been mobilized to conduct initial geological mapping and rock-chip sampling at South Zone prospects including Lost Dog, Steel Creek, Cut-hand Creek, Muruk and Regess. Great Pacific Gold said the initial South Zone results would be reported after assays are received and reviewed. The company currently has two diamond drill rigs operating at Wild Dog and plans to extend systematic drilling into the southern corridor as priority targets are developed. Great Pacific Gold said its Wild Dog Project includes a 15-kilometer structural corridor in East New Britain, with the company pursuing multiple epithermal and porphyry exploration targets. The company also holds the Kesar, Arau and Tinga Valley projects in Papua New Guinea.

Papua New Guinea's petroleum sector has taken another step towards expanding local participation in the country's growing gas industry, with Petroleum Minister Jimmy Maladina approving the National Content Plan (NCP) for the Pasca A Gas Project. Maladina approved the plan following a technical review and compliance assessment by the National Petroleum Authority (NPA). The NCP was submitted by Twinza Oil (PNG) Ltd., operator of the Pasca A Gas Project, and approved under Section 129 of the Oil and Gas Act 1998. The approval establishes a framework intended to increase opportunities for Papua New Guinean workers and locally owned companies to participate in the development and future operation of the project. Maladina said the plan would support education, training, skills development and employment while increasing the participation of PNG-owned businesses and communities in the supply and procurement of goods and services. “This approval gives effect to the objectives and principles of the Petroleum Sector National Content Policy 2023 and is intended to ensure that the development and implementation of the Pasca A Gas Project delivers meaningful and sustainable national benefits to Papua New Guinea,” he said. Local business participation The approved NCP provides opportunities for Papua New Guinean citizens and locally owned companies to participate in professional and technical services required by the project. These include legal, accounting, financial, payroll and other professional services, creating potential opportunities beyond traditional construction and resource-sector contracting. The plan also provides for targeted investment in areas with potential to deliver longer-term economic and social benefits, including health care, education, critical infrastructure, research and development, and technology. For local businesses, implementation of the plan could create opportunities to build capacity, develop supply-chain relationships and position PNG-owned companies to compete for contracts across the project's different development phases. The government expects communities in Gulf Province, as well as Papua New Guineans more broadly, to benefit from the project alongside other major gas developments, including Papua LNG. Pasca A therefore adds to the potential pipeline of activity in PNG's petroleum sector and could generate demand for local labour, services, logistics, procurement and supporting businesses as the project progresses. Maladina said implementation of the NCP would promote the progressive development of national content throughout the relevant licence and project phases. The focus on national content is also intended to ensure that economic benefits from resource development extend beyond the project operator and into the wider domestic economy. Quarterly monitoring during construction The approval comes with regulatory conditions designed to ensure that commitments contained in the NCP are implemented and monitored. Twinza will be required to submit quarterly status reports and implementation updates during the construction phase through the Petroleum Sector National Content Office to the NPA. During production, the company will be required to submit annual status reports. The reports will allow the NPA to assess progress against the commitments, targets, programmes and outcomes contained in the approved plan. Twinza must also maintain complete records of NCP implementation and facilitate monitoring, verification, audits and compliance reviews undertaken by the NPA. The company is required to provide information and reasonable assistance necessary for regulators to verify compliance. The approval remains subject to ongoing regulatory monitoring and compliance with the NCP, the Oil and Gas Act 1998 and applicable petroleum-sector policies. For PNG's private sector, the effectiveness of the plan will ultimately depend on how successfully local companies can access procurement opportunities, develop the required capabilities and participate throughout the Pasca A project lifecycle.

Reeves Envico and CE Group have commenced work on the 22-kilometre transmission line that will connect renewable energy from Tina River with the homes, businesses and essential services of Honiara. Against the rolling hills and demanding terrain of Guadalcanal, work is beginning on a connection that will carry more than electricity. The new transmission line will extend 22 kilometres from the Tina River Hydropower Facility to Lungga Power Station and the Honiara national electricity grid. Once complete, it will carry up to 15 megawatts of renewable power to the capital, helping reduce reliance on imported diesel and supporting cleaner, more reliable and more affordable energy for Solomon Islanders. The commencement of construction was marked at a signing ceremony in Honiara attended by representatives of the Solomon Islands Government, Solomon Power, Australia, Reeves Envico and CE Group. The ceremony recognised a significant step forward for the Tina River Hydropower Development Project-the largest renewable energy initiative undertaken in Solomon Islands. Reeves Envico is delivering the transmission line works as principal contractor, with CE Group engaged as the Electrical Infrastructure Partner. The relationship brings together Reeves Envico’s longstanding connection with Solomon Islands and CE Group’s experience delivering complex electrical works in remote and operationally challenging environments. The scale of the undertaking is significant. The route crosses rolling hills, changing elevations and areas where weather, access and terrain will influence the movement of workers, equipment and materials. Delivering the line will require disciplined planning, technical capability and close coordination with Solomon Power, national workers, communities and the broader project team. It is a demanding scope, but its purpose is deeply human. Reliable electricity supports hospitals, classrooms, communications, refrigeration, government services and local businesses. Its value is felt when essential equipment continues operating, when a student can study and when a business can remain productive. For Reeves Envico and CE Group, those everyday outcomes give the partnership its meaning. Reeves Envico Managing Director Simon Gorman said the signing marked a deeply significant return to the country where the company’s story began. “Reeves’ connection with Solomon Islands began in 1988, with our very first project. To return today and sign this contract is more than an important milestone-it is a privilege,” Gorman said. That history brings both experience and responsibility. The partnership between Reeves Envico and CE Group is grounded in trust, integrity and a shared commitment to deliver work that supports Solomon Islands’ national priorities. For CE Group, the project is its largest contract to date and an opportunity to apply its electrical engineering and construction capability to work of lasting national value. CE Group Managing Director Ryan Johnson said the signing reflected the strength of the relationships that continue to connect Solomon Islands and Australia. “Today’s signing honours that enduring partnership and opens the door to new opportunities for the people of both our nations," Johnson said. Those opportunities extend beyond the physical delivery of the transmission line. More than 190 Solomon Islanders are currently employed across the broader Tina River Hydropower Development Project, with further opportunities expected as construction progresses. Behind that number are workers developing experience, families supported by employment and national capability that will remain beyond the construction period. The wider project also includes education and training initiatives and measures supporting safe employment opportunities for women and girls. Australia is contributing approximately SBD$180 million to the transmission line project through the Australian Infrastructure Financing Facility for the Pacific, combining concessional financing and grant funding. The project is expected to be completed in early 2028. Its magnitude can be measured in kilometres, megawatts and the difficulty of the landscape. Its true legacy, however, will be measured by what it enables: stronger energy security, more dependable essential services, national employment and new possibilities for Solomon Islands communities. For Reeves Envico and CE Group, the intention is clear: to honour the trust placed in the partnership, deliver with integrity and remain focused on the people the work is ultimately intended to serve. The signing ceremony marked the beginning of that responsibility-not its conclusion. The lasting measure of the partnership will be found in the work delivered, the relationships strengthened and the benefits carried forward for Solomon Islands. Beyond borders, progress is built through partnership.

Papua New Guinea’s agriculture sector is strengthening efforts to expand domestic and international market opportunities, with about 30 agriculture professionals taking part in an Australia Awards Short Course focused on agricultural trade, supply chains and export systems. Announced on Aug. 13 and supported by Australia Awards, the initiative aims to strengthen the capacity of PNG agriculture professionals to develop practical solutions that can help farmers, businesses and exporters access new markets and improve the movement of agricultural products from producers to consumers. The focus has significant economic implications for PNG, where more than 85 per cent of the population relies on agriculture for their livelihoods. Improving agricultural trade and market access is therefore closely linked to rural incomes, food security and broader economic growth. Delivered by the University of Queensland in collaboration with Pacific Adventist University, the short course brought together agriculture professionals from government and industry to examine ways to improve partnerships, logistics, supply chains and export systems. The programme reflects the shared interest of Australia and PNG in expanding agricultural trade and developing stronger, more efficient supply chains capable of connecting local producers with domestic and international markets. PNG Biosecurity Authority representative Douglas Siuta said the course highlighted the importance of closer cooperation across the agriculture sector. “This course is helping us understand how the whole system fits together and where we can work more closely. I will take these lessons and connections back to my organisation so we can contribute to real improvements,” Siuta said. The latest course builds on two earlier Australia Awards short courses focused on agriculture, as well as a study tour to Australia, helping to establish a broader professional network of Papua New Guinean agriculture specialists. The network is intended to strengthen collaboration between government and industry and help professionals address the systems that connect producers with markets, including supply chains, logistics and export processes. For PNG, improving these systems could help address practical barriers faced by agricultural businesses and producers seeking to increase production, reach new buyers and participate more effectively in domestic and international trade. Stronger market linkages could also help ensure that increased agricultural production translates into greater economic opportunities for farmers and rural communities. Australia has reaffirmed its commitment to supporting Papua New Guinean leaders to strengthen institutions and develop practical solutions that deliver long-term benefits for the agriculture sector. Through Australia Awards, Australia will continue working with PNG to invest in people, strengthen institutions and support Papua New Guinean leaders in turning knowledge, partnerships and shared priorities into long-term progress.

The Centre for Excellence in Financial Inclusion (CEFI) and Credit Guarantee Corporation PNG (CGC) have signed a memorandum of understanding to strengthen financial literacy, business capability and access to finance for micro, small and medium-sized enterprises across Papua New Guinea. The agreement formalizes an existing partnership between the two organisations and establishes a framework for joint financial literacy programmes, entrepreneurship training, business development support and referrals to financial institutions participating in CGC’s credit guarantee programme. CEFI and CGC will collaborate on financial literacy and capacity-building initiatives covering entrepreneurship, banking and financial management, while raising awareness of their respective roles in expanding access to finance and financial inclusion. A key element of the partnership will be a referral pathway for startup businesses seeking finance. CEFI Acting Executive Director Peter Samuel said the growing number of MSMEs accessing financial services made it important to ensure business owners had the skills to manage their finances effectively. “As CGC’s portfolio continues to grow, so too does the number of MSMEs participating in the market,” Samuel said. He said greater access to finance did not necessarily mean that beneficiaries had the knowledge required to manage their businesses successfully. “Our objective is to ensure that recipients of guaranteed facilities are equipped with the knowledge and skills needed to manage their businesses effectively, maintain proper financial records and avoid the risks associated with poor financial management,” he said. Samuel said CEFI would complement CGC’s credit guarantee facilities with practical capacity-building programmes, including its Business Essential Skills Module, Digital Financial Literacy Module and financial literacy programmes covering budgeting and savings. He said combining access to finance with business incubation and financial education would provide entrepreneurs with stronger support to establish sustainable businesses. “The government continues to emphasise the importance of supporting MSMEs. However, support must go beyond financing alone,” Samuel said. “We also need clear pathways that provide incubation, capacity building and business acceleration programmes to help MSMEs become sustainable and contribute meaningfully to economic growth.” CGC Chief Executive Officer Dominic Sikakau said the agreement formalised a partnership that had already supported several initiatives. “We have already collaborated on a range of initiatives, so today’s memorandum of understanding simply formalises a relationship that has existed for quite some time,” Sikakau said. He said loan defaults remained a key challenge for CGC’s guarantee programme and were often linked to gaps in business knowledge and financial management skills. “Through our partnership with CEFI, we hope to strengthen the capacity of MSMEs by equipping them with the knowledge and skills to manage their finances effectively, build sustainable businesses and ultimately reduce the risk of default,” he said. Sikakau also highlighted CGC’s Loan Referral Platform, which allows MSMEs to submit loan applications online to participating financial institutions. He said integrating the platform into CEFI’s financial literacy programmes could improve awareness and accessibility, particularly among entrepreneurs in rural and remote areas. The organisations said the partnership would help create stronger pathways for entrepreneurs, reduce barriers to finance and support private-sector growth, financial inclusion and socioeconomic development in Papua New Guinea.

The Papua New Guinea Tourism Promotion Authority (PNGTPA) is moving to revive a dormant ferry in Port Moresby Harbour as part of efforts to expand marine tourism, develop new tourism products and unlock greater economic value from the capital's coastline. PNGTPA has partnered with Happy Soles Ltd. and Marine Contract Management to operate and manage the vessel, which has been out of service for some time. The partnership was formally signed on Aug. 6, with the three organizations expected to work together to return the vessel to safe and professional operation. For PNG's tourism industry, the initiative provides an opportunity to diversify the visitor experience beyond traditional land-based attractions while increasing private-sector participation in marine tourism. PNGTPA Chief Executive Officer Eric Mossman Uvovo said returning the vessel to service was an important step in making better use of tourism assets and developing new opportunities for the industry. “This boat has been sitting idle for some time, and today marks the beginning of a new chapter. Our goal is to get it back on the water as quickly and safely as possible so it can support PNGTPA's work in promoting Papua New Guinea and creating more tourism opportunities,” Uvovo said. New marine tourism products The vessel will initially be used for tourism promotion activities, official engagements and sightseeing around Port Moresby. It is also expected to provide a platform for developing commercial marine tourism products. Potential offerings include island cruises, private functions, family celebrations and sightseeing experiences, creating opportunities for local businesses to provide supporting services. Happy Soles Managing Director Yiannis Nicolaou said the company plans to upgrade the vessel with more comfortable seating and modern features while developing experiences that complement existing marine services in Port Moresby. “We want to give visitors something different by creating enjoyable experiences on the water,” Nicolaou said. The planned upgrades and operation of the vessel could generate business opportunities in hospitality, catering, events, transportation, maintenance and other tourism-related services. Marine Contract Management Managing Director Capt. Matthew Dieni said his company would focus on vessel maintenance, safety and professional operations. “It is an honor to partner with PNGTPA on this important project. My team and I are committed to ensuring the boat is well maintained, safely operated and ready to deliver quality services,” Dieni said. Expanding marine tourism infrastructure The partnership forms part of PNGTPA's broader effort to strengthen the country's marine tourism infrastructure, including the development of jetties and waterfront facilities. Uvovo said Port Moresby would provide a starting point, with the potential to replicate similar initiatives in other coastal provinces and destinations. Papua New Guinea's extensive coastline, islands and marine environment provide significant potential for marine tourism, but developing that potential requires investment in infrastructure, transportation links, tourism facilities and professionally operated visitor experiences. For the tourism sector, expanding marine-based products could increase visitor spending and encourage longer stays by giving tourists additional activities while in the country. It could also create opportunities for local communities and small businesses to participate in the tourism supply chain as marine tourism products expand. PNGTPA said it would continue working with industry partners to unlock the potential of the country's coastline and coastal attractions, with the broader objective of positioning Papua New Guinea as a destination offering authentic and memorable experiences. The return of the Port Moresby ferry therefore represents more than the reactivation of an idle tourism asset. It provides a potential platform for developing a new segment of PNG's tourism economy, with longer-term opportunities to expand marine tourism services beyond the capital to other coastal destinations across the country.

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

For more than two decades, CE Group has delivered complex electrical and engineering projects across Australia and the Pacific, building a reputation for providing practical, end-to-end engineering solutions in some of the region's most challenging operating environments. From major mining operations and hospitals to water infrastructure and renewable energy developments, the company has supported clients with integrated engineering services across a diverse range of sectors. Founded in 2000 in South East Queensland, CE Group has steadily expanded its footprint beyond Australia into Papua New Guinea, Fiji, Solomon Islands, Vanuatu and New Zealand. Today, the privately owned business provides a full suite of services, from engineering design and electrical construction to switchboard manufacturing, commissioning and ongoing maintenance. Rather than engaging multiple contractors, clients increasingly turn to CE Group as a single integrated delivery partner capable of managing projects from concept through to completion. As infrastructure projects continue to grow in scale and complexity, integrated project delivery has become increasingly important. In response to this shift, CE Group has strengthened its in-house engineering capability, enabling it to become involved much earlier in the project lifecycle. Early engineering engagement helps reduce project risks while providing greater certainty around cost, quality and schedule. It also improves coordination and collaboration between project teams, identifies potential challenges before construction begins, and supports more efficient project delivery.  By bringing engineers, designers, manufacturers and construction teams together under one roof, the company aims to deliver practical, buildable solutions that improve project outcomes. The move also reflects broader changes across the infrastructure sector. Throughout Australia and the Pacific, governments and private investors continue to increase investment in renewable energy, water security, mining, industrial facilities and other critical infrastructure.  Many project owners are seeking delivery partners with the technical capability to support projects from early planning and design through construction, commissioning and long-term maintenance, rather than contractors focused solely on construction. For CE Group, expanding its engineering capability positions the business to meet that demand. The company says earlier involvement in project planning enables it to improve constructability, identify potential issues before construction begins, streamline project delivery and develop more efficient engineering solutions. These capabilities have already been demonstrated across a diverse portfolio of projects. In Papua New Guinea, CE Group has contributed to major developments including the Angau Memorial Hospital Redevelopment and APEC Haus, while across Australia it has delivered electrical and engineering solutions for mining, water and industrial infrastructure projects. Alongside strengthening its technical capability, CE Group continues to invest in its people and regional presence. The company now employs more than 450 people across multiple countries and maintains a strong focus on safety, workforce development and local capability building. Investing in local talent remains a key part of its regional strategy, particularly across Pacific markets where demand for skilled engineering and technical expertise continues to grow. Looking ahead, the company expects continued investment in the energy transition, industrial expansion and essential infrastructure to create new opportunities across the region. With its expanded engineering capability and integrated delivery model, CE Group believes it is well positioned to support clients through every stage of increasingly complex projects. As infrastructure demands continue to evolve, the company's strategy remains focused on combining engineering expertise, practical execution and long-term partnerships to deliver projects more efficiently, safely and reliably. In an environment where project certainty is increasingly valued alongside technical capability, CE Group's integrated approach is designed to help clients achieve better outcomes throughout the project lifecycle.

Papua New Guinea has launched a revised manual for the seismic design of bridges, updating earthquake risk information and engineering requirements for the planning, design and construction of bridges across the country. The Seismic Design Manual for Bridges in Papua New Guinea 2025 Revision was launched Aug. 13 in Port Moresby by Department of Works and Highways Secretary Gibson Ali Holemba, who formally launched the manual on behalf of the government. The revision replaces seismic bridge design guidance that has been used by engineers in PNG for about 40 years. PNG is exposed to significant earthquake risks because of its location at the convergence of major tectonic plates and microplates. Major earthquakes, including the 1971 Madang earthquake, the 1985 Bialla earthquake and the 2017-18 Southern Highlands earthquake, have damaged roads, bridges, buildings and other infrastructure. The revised manual incorporates advances in engineering, materials, analytical methods and scientific understanding of seismic hazards. It also incorporates updated information from a probabilistic seismic hazard assessment supported by the Australian government through Geoscience Australia. The assessment provides more detailed seismic risk information at provincial and district levels, giving engineers a stronger basis for determining bridge design requirements at specific locations. Holemba said the revised manual should be treated as a national requirement rather than simply a technical reference. “Sound engineering and standards are not optional guidance. They are not optional. They are fundamental requirements and mandatory for protecting lives,” he said. The Department of Works and Highways will incorporate the revised requirements into project planning, design briefs, terms of reference, tender documents, technical specifications, design reviews, construction and asset acceptance procedures. All new bridge projects must demonstrate compliance with the revised requirements from the launch date, regardless of whether they are funded by the national government, loans, development partners, tax credit arrangements, provinces or districts. Bridge acceptance will also require technical evidence including site investigations, geotechnical assessments, seismic calculations, approved drawings, independent technical reviews, material test results, construction records and certification by qualified registered engineers. The revised approach is intended to ensure bridge designs reflect the specific conditions at each project location. Previous design parameters did not always account for site-specific seismic conditions. The updated assessment provides engineers with more detailed location-specific information, helping reduce the risk of under-design while avoiding unnecessary design requirements and costs. The manual also addresses structural ductility, lateral strength, soil instability, slope failures, flooding, debris impact and interactions between seismic and climate-related risks. For PNG, bridge resilience has implications beyond the structural integrity of individual bridges. Bridge failures can cut communities off from hospitals, schools, markets, ports and airports, making resilient bridge infrastructure important to national connectivity and public safety. Holemba also warned against allowing construction costs to drive engineering decisions. “Engineering must dictate the price, not cost dictating the engineering designs,” he said. He said the lowest initial construction price did not necessarily represent the best value if engineering requirements were compromised and infrastructure could not remain safe and serviceable throughout its intended life. The department will establish professional training, compliance checklists, independent review procedures and periodic technical audits to support implementation of the revised manual. Existing bridges on strategic national highway corridors in high-risk areas will also be progressively assessed and prioritized for strengthening, retrofitting, rehabilitation or replacement. More than 1,000 bridges have been inspected and assessed with support from the Asian Development Bank and World Bank, including load-rating assessments to identify vulnerable structures requiring further work. The revision was supported by the Australian government through the Department of Foreign Affairs and Trade and Geoscience Australia. Scientific work also involved seismic information from the Port Moresby Geophysical Observatory and Rabaul Observatory, as well as contributions from bridge engineering, geotechnical and technical specialists. The launch begins the implementation phase of the revised manual. The department is expected to review it as new scientific information, engineering lessons and technologies become available. Holemba said the effectiveness of the manual would ultimately be measured by the performance of bridges built under its requirements. “The true value of this manual will not be measured by the number of copies printed,” he said. “It will be measured by the bridges that remain standing.” The revised manual provides engineers and other professionals involved in bridge development with an updated, locally relevant basis for designing infrastructure capable of withstanding PNG’s seismic risks.