Prime Minister James Marape receiving a COVID-19 vaccine in April 2021 (PNG PM Media) Article by Stephen Howes National elections will be held in PNG in the middle of this year. Elections are held every five years, and are very popular events. Though voting is voluntary, voter turnout is just below that of Australia, where voting is compulsory. An extraordinary number of political candidates compete for office. The average number of candidates per seat has grown from eight in 1977 to 30 in 2017, surely a global record. 111 men but no women were elected in the 2017 elections. It is possible (though increasingly unlikely) that special measures will be put in place in the next few months so that that result is not repeated in 2022. If not, the only remaining hope is that at least a few of the growing number of women who stand at elections are successful at the hustings. It is impossible to predict election results, as there are no opinion polls, and party structures are very fluid. But James Marape, Prime Minister since 2019 when he ousted Peter O’Neill in a mid-term vote of no confidence, is the favourite, simply because he is the incumbent. In each of the last three elections, the incumbent Prime Minister has kept his job. This is because PNG law was amended at the turn of the century to require that the party with the most members of parliament (MPs) elected be given the first chance to form a coalition of government. MPs are normally attracted to the party of the prime minister. Currently, Marape’s party, PANGU, has 34 MPs, almost three times the size of the next party. There is a high turnover of MPs, but even if there is a swing against it, PANGU will likely emerge from the elections as the biggest party, giving Marape first go at the top job. Whoever wins the elections will have to deal with two key issues. One is COVID-19. Vaccination rates increased in PNG in October and November as COVID-19 took off, but with very high levels of vaccine hesitancy, by the latest estimate only 2.5% of the population is fully vaccinated. PNG will have to navigate 2022 without significant vaccine coverage. COVID-19 hit PNG hard in the second half of 2021, and it must be highly likely that there will be another large wave associated with the introduction of the Omicron variant and perhaps election campaigning. The other issue facing the country is the desperate need to raise economic growth and create more jobs. COVID-19 is itself an economic problem, and the low level of vaccination in PNG is likely to hinder labour mobility, trade and investment. There might also be further internal lockdowns. While COVID-19 has been bad for growth, it was already sluggish before the onset of the pandemic. In the absence of data on gross national income and given the enclave nature of the extractive (resource) sector, non-resource gross domestic product is the best measure of national economic activity. From 2014 to 2019, this grew in real terms by only 0.9 per cent a year on average. The budget projects this to accelerate to an annual average of 4.4 per cent from 2021 to 2027. How is unclear. Perhaps one of the various resource projects currently being negotiated will be finalised within this period and its construction will give the economy some much-needed stimulus. But with all the uncertainty around the projects currently under discussion, the government wisely isn’t counting on this. Growth in government expenditure this year, including much needed health expenditure increases, will help economic growth, but PNG is running record deficits to support expenditure in the face of COVID-19. Rapid expenditure growth cannot be sustained. While the latest budget allows for a 3.5 per cent increase in expenditure after inflation in 2022, it doesn’t allow for any subsequent expenditure growth after that until 2027. The biggest drag on growth since 2014 has been foreign exchange shortages, which remain a problem to this day. In annual surveys, PNG’s business leaders have listed foreign exchange as one of their top four worries every year between 2014 and 2021, and often as their leading concern. PNG’s central bank has been content to ration foreign exchange to protect the exchange rate and its foreign exchange reserves. The government recently amended the Central Banking Act to require the Bank of Papua New Guinea to take account of the growth as well as the inflationary consequences of its policies. Given the disastrous impact of foreign exchange rationing on growth in recent years, it is hoped that this encourages the Bank of Papua New Guinea to change tack and eliminate foreign exchange rationing. Ultimately, whoever wins the 2022 election is going to find themselves in the invidious position of having to exercise fiscal restraint while trying to accelerate economic growth. It won’t be easy. This is a revised version of an article that first appeared on East Asia Forum. Disclosure: Last year the author served on the PNG Independent Advisory Group (IAG) which made recommendations in relation to the Central Banking Act mentioned above. For details, see the IAG website. This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Stephen Howes is the Director of the Development Policy Centre and a Professor of Economics at the Crawford School.

Photo:Students in Kimbe West Britain PNG Article by Grant Walton and Husnia Hushang It’s back! This year Papua New Guinea (PNG) will implement another fee-free education policy. In June 2021, the government announced that, for the fifth time in PNG’s history, parents will no longer have to pay school fees to send their children to school. This new policy is a significant backflip for Prime Minister James Marape’s government; in 2019 Marape announced the abolition of the country’s long-running fee-free education policy, the Tuition Fee Free (TFF) policy. The new policy is to be welcomed, particularly given that many Papua New Guineans have been hit hard by the economic fallout of COVID-19. However, any initial optimism must be tempered when considering previously unsuccessful attempts to sustain fee-free education policies in the country (three of the four previous attempts lasted no longer than one year). The question is, once implemented, how can the new policy maintain political and, by extension, financial support? To help answer this question, it is worthwhile looking at why previous attempts to introduce fee-free education in PNG faltered. In a recent journal article, we examine the rise and fall of political support for the TFF policy (2012–2019), PNG’s longest running fee-free education reform. Fee-free education was held up as one of the then Prime Minister Peter O’Neill’s flagship reforms. However, by examining publicly available documents, including over 10 years of budgetary and policy papers, we show that political support for the TFF policy started to decline soon after it was introduced. Between the 2012 and 2019 budgets, in real terms, allocated funding fell by almost 30%. As a proportion of the overall budget, the percentage of funds allocated for education subsidies fell from 5.9% in the 2012 budget to 3.8% in 2019. We show that this decline in financial and political support for the TFF policy during O’Neill’s tenure was accompanied by a steady shifting of administrative powers and funding from national to subnational governments. This included passing the District Development Authority Act 2014 (which increased the autonomy of district governments), and transferring responsibility for the administration of the TFF policy to five select provinces (Milne Bay, Enga, Morobe, East New Britain and New Ireland), starting with Enga in 2014. The government also increased funding for provinces and district governments through, for example, constituent development funds (known as Services Improvement Program funds), transferring 30% of the TFF subsidy to districts, and increasing provincially-controlled educational function grants. By the time Marape took the reins, the national government (as well as local schools) had lost control over much of the TFF subsidy and other funding designed to aid its implementation. Both Marape and his treasurer Ian Ling-Stuckey said the government abolished the TFF policy because of the state of the economy they inherited from the O’Neill-led government, levels of corruption associated with the policy, and concerns about education quality, attrition, graduate opportunities and parental responsibility (some feared that not paying fees made parents less inclined to engage with schools). While there is a degree of truth to all of these concerns, it is also true that the new Marape government, initially at least, significantly cut the education subsidy while continuing to increase funding to subnational governments. The Marape government also promised to retain agreements made with the five provinces (Milne Bay, Enga, Morobe, East New Britain and New Ireland) that the O’Neill government had allowed to manage (previously national) government school fee grants/subsidies, along with an additional three (East Sepik, Northern and Eastern Highlands). In other words, Marape ultimately prioritised subnational administrations over national fee-free education. There are good arguments for shifting administrative, political and financial power to lower levels of government. Still, many scholars note that, to ensure equity and a coordinated approach, fee-free education policies work best when they are centrally administered and resourced. In PNG, many subnational governments, particularly districts, do not have the capacity to effectively manage education funds. In our paper, we go into far more detail about how policy-makers and others can anticipate and respond to arguments that are often raised against fee-free education policy (including that they encourage laziness amongst parents). One key takeaway is that, if PNG is to introduce a more sustainable fee-free education policy, it will be crucial that politicians are able to resist calls to decentralise the management and funding of the policy to lower levels of government – particularly where subnational governments lack the capacity to manage devolved funds. Subnational governments should play a role in delivering education policy, but not to the detriment of national fee-free education. Recently, there have been some signs that the government’s new education policy might be trying to strike the right balance. The policy allocates 15% of the education subsidy for provinces and districts to procure teaching and learning materials. This is half of what was earmarked for districts under the TFF policy. Still, politicians in PNG are incentivised to channel resources into subnational administrations because they are better able to distribute funding to their supporters and, in most cases, less likely to be held accountable. Given this, the national government will likely continue to face pressure to redirect funding and administrative power to subnational governments. Resisting this pressure, and striking the right balance between central and subnational funding and administration, is all the more important given that, in the 2022 budget, funding for the new policy – supported by $35 million of Australian aid – is 34% less than the O’Neill government allocated for the TFF policy in 2012. This blog is based on an article in Asia & the Pacific Policy Studies journal, The politics of undermining national fee-free education policy: Insights from Papua New Guinea by Grant Walton and Husnia Hushang. All articles in the journal are free to read and download. Disclosure: This research was supported by the Pacific Research Program, with funding from the Department of Foreign Affairs and Trade. The views are those of the authors only. This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Dr Grant Walton is a Fellow at the Development Policy Centre and Chair of the Transnational Research Institute on Corruption and the author of Anti-Corruption and its Discontents: Local, National and International Perspectives on Corruption in Papua New Guinea. Husnia Hushang is a School Administrator at the Research School of Economics, and a casual Research Assistant at the Development Policy Centre at the Crawford School of Public Policy, Australian National University. She has a Masters of Public Policy and a Graduate Diploma of Public Administration from the ANU, and a Bachelor of Law and Political Science from Kabul University.

Photo credit: Australian High Commission by Stephen Howes When the COVID-19 pandemic hit, the Australian government reversed its earlier policy of cutting aid, and started to increase it. Aid increased from 2019/20 (before the pandemic) from $4.29 billion to $4.56 billion in 2020/21 (the first year of the pandemic). (All amounts are adjusted for inflation, and expressed in 2021 prices.) But this year, the government started to cut aid again, not all the way back to its pre-pandemic level but close to it. The budget for aid in 2021/22 is $4.34 billion, not much more than its 2019/20 level. According to the forward estimates, and assuming that the budget is brought down before the federal elections next year, 2022/23 aid will be at only $4.1 billion. This will not only be lower than aid was in the year immediately prior to the pandemic, but the lowest level of aid during any year since the Coalition took office in 2013. We are heading towards this outcome because the government’s COVID-19 aid response was designed on the basis that the pandemic would be short-lived. For example, the Pacific COVID-19 Response Package allocated an additional $200 million in 2020/21 and $100 million in 2021/22. With the additional pandemic-related funding petering out, and no real increase in the underlying or “core” aid budget, total aid is slated to fall. This makes no sense at all. Clearly the pandemic is taking a lot longer to resolve than was hoped. One good measure of how far countries are from returning to normality is their vaccination rate. After all – as has been endlessly repeated in Australia – vaccination is the only way out. The weighted average vaccination rate for the top ten recipients of Australian aid is just 20% (weighted by their share of total top ten aid). That compares to 73% for Australia, so it is less than one-third. For two of our top ten aid recipients, the vaccination rate is less than 10% (PNG and Solomon Islands), and there are only two where it is greater than 50% (Fiji and Vietnam). There are any other number of reasons why it would make sense to increase aid. Countries need support not only for vaccination, but for economic recovery. There are numerous other global crises that Australia should be supporting and isn’t, such as the African famine/drought, and the plight of refugees whose food rations have been cut. Public opinion seems to have become more favourable to aid. We have just committed to spend more aid on climate change. And we have become one of the least generous rich country donors. Above all though, there is the simple logic that more aid is needed during the pandemic (as the government itself acknowledged by providing extra aid), and that the pandemic is taking longer to resolve than expected. The unavoidable conclusion is that more aid will need to be provided than originally expected. This logic is surely on its own compelling enough to prevent next year’s aid budget being brought below pre-pandemic levels and becoming this government's lowest foreign aid budget ever. Disclosure: This research was undertaken with the support of The Bill & Melinda Gates Foundation. The views represent those of the author only. Caption: Greeting the arrival of an Australian funded COVID-19 support package, Solomon Islands (DFAT/Flickr)   This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Stephen Howes is the Director of the Development Policy Centre and a Professor of Economics at the Crawford School.

Photo credit: Devpolicy by Stephen Howes Yesterday, Telstra announced that it was buying Digicel Pacific. Telstra itself is only paying $270 million, and the Australian government $1.33 billion. Yet, Telstra is obtaining 100% ownership. The deal is certainly an attractive one for Telstra. But does it make sense for Australia, and for the Pacific? Digicel has had a transformational impact in the Pacific, but now has too much market power. As the Telstra release explains, it holds the dominant position in all the Pacific countries in which it operates, except for Fiji, where it is in second place. In Papua New Guinea, which I know best, and which is by far Digicel's biggest market, the company  has a 92% share of the mobile phone market. That makes Digicel effectively a monopoly in PNG. And that is why it is so profitable: like any monopolist, it exploits its market power. Australian and PNG researchers have been tracking mobile internet prices in PNG since Australia gifted it a new underwater cable . Their conclusion is that since the completion of that cable in December 2019 to today there has been no decrease in mobile internet prices. The reason is simple: the lack of retail competition. Michelle Nayahamui Rooney, Martin Davies and I last year exposed Digicel PNG’s predatory loan scheme. Digicel lends phone credit to its customers. They pay it back when they next top up. Our estimate is that Digicel made a 17% return from such loans every week, which is equivalent to an unbelievable 351200% a year. Is this really the way in which Australia want to engages in the Pacific – owning an enterprise that keeps prices high for consumers, and rips them off when they are desperate to make a call? Any monopolist is necessarily engaged in a battle between the consumer and their profits. At some point, Telstra will end up going toe-to-toe with the PNG telecom regulator, NICTA, as Digicel has done several times. It’s going to be awkward for both Telstra and the Australian government. Many will welcome the investment as a sign of Australian commitment to the Pacific. However, if we want to invest in the telecom sector in the Pacific, we should be backing alternatives to Digicel, to push prices down and improve services, not buying out the dominant player. Amalgamated Telecom Holdings based in Fiji is the Pacific’s second biggest telecom provider. It is currently planning to enter the PNG mobile market with support from the Asian Development Bank. This is the sort of investment we should be financing. That Australia has bought Digicel shows the extent to which the Pacific is now viewed through a China lens. That’s unfortunate. China is a massive economic power. Its companies will have increasing stakes in economies around the world. That is a fact we have to accept. The Australian government also needs to decide if its only goal is to counter China or if it is still seeks to promote Pacific development. When I was AusAID's Chief Economist, Digicel was the new kid on the block in the Pacific, and it was successfully challenging state-owned telcos that until then had been dominant. In 2006, in Foreign Minister Alexander Downer's flagship Pacific 2020 report, we wrote glowingly about the competition that various Pacific countries had recently started allowing in the mobile phone sector. Our analysis was right then, and remains relevant today. Yet here we are, in 2021, doing the opposite: rather than supporting greater competition in the telecom sector, subsidising the purchase of the incumbent monopolist. The decision to buy Digicel Pacific should be reversed. If it is too late for that, the Australian government should at least – in return for all its cheap and risk-reducing finance – oblige Telstra to operate Digicel for the benefit of the people of the Pacific rather than solely for its shareholders through an agreement that makes it clear that the Australian company is not only expected to return the cheap loan it has been given, but also reduce prices, and end rip-offs.   This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Stephen Howes is the Director of the Development Policy Centre and a Professor of Economics at the Crawford School.

Photo: Joyce Bay settlement (Desmond Narongou) by Desmond Narongou Joyce Bay settlement, formerly known as Horse Camp, is a notorious settlement in Port Moresby, Papua New Guinea (PNG). It has been known for criminal activity, and as a place where many criminals live. The settlement is located in the Port Moresby South Electorate of the National Capital District, and is one of the oldest settlements in the city. The community includes people from Gulf Province and at least 11 other ethnic groups from throughout PNG. The population was estimated at more than 10,000 in 2013, and is believed to be around 13,000 now. The rapid increase in the population (from about 7,000 in the year 2000) reflects an influx of migrants from rural to urban areas, seeking employment opportunities and access to improved health and education services. Over the last few years, some major changes have taken place within the community, which have brought radical shifts to people’s mindset and behaviour. New infrastructure development, and projects providing opportunities for youths and business development, have contributed to a transformation for the Joyce Bay settlement. According to a report by the Asian Development Bank, the Joyce Bay community had limited livelihood options in 2013. The most common jobs were security guard for males and shop assistant for females. Some women worked as market vendors, selling fresh food brought in by producers from the outskirts of Port Moresby. There were a handful of skilled people such as carpenters, plumbers and painters, who were engaged in ad hoc contracts. Wages were low, with no system to enforce minimum wages for casual or part-time workers. These workers also had limited access to credit. Starting in 2013, the Ginigoada Foundation, with City Pharmacy Ltd and the National Capital District Commission (NCDC), has opened up opportunities for youths, and others, to attend financial literacy training and small business training. This has empowered them to venture into new business activities to improve their lifestyle and sustain themselves. In that same year, Joyce Bay underwent major road works, providing much needed access to transport within the settlement after decades without. This was funded by Moresby South District Development Authority and the NCDC. This has paved the way for other infrastructural developments to take place, including a sewerage system and water supply. In 2016, a local community hall was constructed. The community hall has a conference room, store room, kitchen and toilet. It also has a multipurpose sports court that can be used for community events. In 2019, water company Eda Ranu (now merged with Water PNG) and Kumul Consolidated Holdings commissioned a multimillion kina Joyce Bay Sewage Treatment Facility, which was funded by the PNG government and the Japanese aid agency JICA. A number of local churches were also established, during the early 2000s, including my church. Taken together, this is a big impact project situated in the heart of the community. It has been championed by the local MP, Justin Tkatchenko, who is keen on rapidly transforming his electorate. Alongside these positive developments, I’ve observed changes in people’s behaviour and attitudes. Youths have been kept busy with sports, which reduces thoughts of engaging in illegal activities. The church has also attracted a lot of youths to its programs and activities, which has contributed to the big improvement in the community. When I came to Port Moresby in 2018, I met up with some of the boys from my church. Joe Alfred, Paul Kore and Sasae Ray are some of my best friends, and have been living in the area since the 1980s when their families migrated from Gulf Province. I asked them about the stories I heard about the community, and they said it was far worse before than it was now. Joyce Bay was a no-go zone, and I was so afraid to go there myself for our church fellowship. After my first visit, I was more nervous and afraid and had to ask my friends to escort me to and from the bus stop and the church. Fast forward to today, and I’ve spent three years moving around the Joyce Bay community every weekend. I’ve witnessed the improvements as well as heard about them. In Joyce Bay, there are a lot of challenges which are yet to be overcome, for example, in terms of good water supply and other sanitary solutions to improve the health and hygiene of the community, and improved drainage as the Joyce Bay area is subjected to flooding during the rainy season. Unemployment remains a challenge in the community. But the future looks much brighter for Joyce Bay inhabitants. by Desmond Narongou Joyce Bay settlement, formerly known as Horse Camp, is a notorious settlement in Port Moresby, Papua New Guinea (PNG). It has been known for criminal activity, and as a place where many criminals live. The settlement is located in the Port Moresby South Electorate of the National Capital District, and is one of the oldest settlements in the city. The community includes people from Gulf Province and at least 11 other ethnic groups from throughout PNG. The population was estimated at more than 10,000 in 2013, and is believed to be around 13,000 now. The rapid increase in the population (from about 7,000 in the year 2000) reflects an influx of migrants from rural to urban areas, seeking employment opportunities and access to improved health and education services. Over the last few years, some major changes have taken place within the community, which have brought radical shifts to people’s mindset and behaviour. New infrastructure development, and projects providing opportunities for youths and business development, have contributed to a transformation for the Joyce Bay settlement. According to a report by the Asian Development Bank, the Joyce Bay community had limited livelihood options in 2013. The most common jobs were security guard for males and shop assistant for females. Some women worked as market vendors, selling fresh food brought in by producers from the outskirts of Port Moresby. There were a handful of skilled people such as carpenters, plumbers and painters, who were engaged in ad hoc contracts. Wages were low, with no system to enforce minimum wages for casual or part-time workers. These workers also had limited access to credit. Starting in 2013, the Ginigoada Foundation, with City Pharmacy Ltd and the National Capital District Commission (NCDC), has opened up opportunities for youths, and others, to attend financial literacy training and small business training. This has empowered them to venture into new business activities to improve their lifestyle and sustain themselves. In that same year, Joyce Bay underwent major road works, providing much needed access to transport within the settlement after decades without. This was funded by Moresby South District Development Authority and the NCDC. This has paved the way for other infrastructural developments to take place, including a sewerage system and water supply. In 2016, a local community hall was constructed. The community hall has a conference room, store room, kitchen and toilet. It also has a multipurpose sports court that can be used for community events. In 2019, water company Eda Ranu (now merged with Water PNG) and Kumul Consolidated Holdings commissioned a multimillion kina Joyce Bay Sewage Treatment Facility, which was funded by the PNG government and the Japanese aid agency JICA. A number of local churches were also established, during the early 2000s, including my church. Taken together, this is a big impact project situated in the heart of the community. It has been championed by the local MP, Justin Tkatchenko, who is keen on rapidly transforming his electorate. Alongside these positive developments, I’ve observed changes in people’s behaviour and attitudes. Youths have been kept busy with sports, which reduces thoughts of engaging in illegal activities. The church has also attracted a lot of youths to its programs and activities, which has contributed to the big improvement in the community. When I came to Port Moresby in 2018, I met up with some of the boys from my church. Joe Alfred, Paul Kore and Sasae Ray are some of my best friends, and have been living in the area since the 1980s when their families migrated from Gulf Province. I asked them about the stories I heard about the community, and they said it was far worse before than it was now. Joyce Bay was a no-go zone, and I was so afraid to go there myself for our church fellowship. After my first visit, I was more nervous and afraid and had to ask my friends to escort me to and from the bus stop and the church. Fast forward to today, and I’ve spent three years moving around the Joyce Bay community every weekend. I’ve witnessed the improvements as well as heard about them. In Joyce Bay, there are a lot of challenges which are yet to be overcome, for example, in terms of good water supply and other sanitary solutions to improve the health and hygiene of the community, and improved drainage as the Joyce Bay area is subjected to flooding during the rainy season. Unemployment remains a challenge in the community. But the future looks much brighter for Joyce Bay inhabitants.   This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Desmond Narongou is a freelance researcher and writer. He graduated with a Bachelors Degree of Commerce in Information Technology from PNG University of Technology in 2017.

Women selling coconut and bottle gourd in Intoap, PNG (P. Mathur/Bioversity International/Flickr) The socio-economic impacts of COVID-19 are devastating communities in the Pacific and Timor-Leste as much as the virus itself, and sometimes to an even greater extent. World Vision surveyed 752 households (with an average of six people per household) in Papua New Guinea, Solomon Islands, Timor-Leste and Vanuatu in late 2020 to better understand the secondary impacts of the pandemic at the community level. The sample size was relatively small (because the survey was done in an emergency context under government restrictions), but still the results provide a valuable insight into the deep and sometimes unexpected knock-on effects of COVID-19 in the region. Unsurprisingly, loss of livelihoods was the number one concern for the households surveyed. Almost 60% of respondents had either lost their job, lost income, or resorted to alternative sources of income due to the economic impacts of the pandemic. The top five reasons cited by households for this loss of income were reduced demand for goods/services (29%), closed markets (20%), lack of access to livelihood inputs such as seeds and materials (18%), movement restrictions (15%), and transport limitations (10%). These disruptions are crippling the same industries that are the traditional drivers of Pacific economies – tourism, agriculture, small- and medium-sized business and money sent home by seasonal workers. Street vendors and farmers have been the hardest hit, with 56% of vendors and 55% of agriculture and livestock workers saying their work was fully or severely affected by the pandemic in the two weeks before the survey. Extent of COVID-19 impacts on livelihoods in the past fortnight (2020) Source: World Vision Report Pacific Aftershocks This data is consistent with concerns raised by the Lowy Institute that the Pacific has been particularly battered by the economic fallout of COVID-19 and that it could face a potential ‘lost decade’ of economic progress as a result. On current projections, average income per person in the Pacific will not recover to 2019 levels until 2028 unless a multi-year recovery package is urgently adopted. Loss of livelihoods isn’t just affecting consumer activity; it is having significant ripple effects across Pacific societies. The ‘Pacific Aftershocks’ survey revealed the cruel choices families are forced to make as their incomes collapse, with households resorting to selling assets and even skipping meals to cope: Only half of households surveyed were able to fully meet their food expenses, with one in four (24%) skipping meals or eating cheaper meals since COVID-19 More than half (51.7%) of households have drawn down on savings to cope with loss of income 5% of households had sold productive assets such as livestock or equipment 14% of households have sent their children to work to help make up for lost income 14% have engaged family members in begging or high-risk jobs With tourism expected to be one of the last sectors to recover from the pandemic, there is a real risk that the Pacific could face its own version of ‘long COVID’ – a protracted, slow climb back to economic normality over the next decade, during which the socio-economic impacts above could become a type of ‘new normal.’ But this doesn’t have to be the case. In the short-term (during the next six months), work is needed to urgently scale up social protection measures (such as cash and voucher assistance and, where this is not possible, food assistance) to help poor families with disrupted incomes meet their immediate needs. In many contexts across the Pacific region, assistance in the form of cash and vouchers minimises the distortion to markets while ensuring families do not resort to negative coping mechanisms such as eating less or forcing their children to work. To build back better in the medium and longer-term (the next one to five years), a suite of initiatives should be deployed to stimulate the Pacific economy and rebuild livelihoods. This could include improving access to finance for small businesses, strengthening market systems so they work better for the poor, investing in women’s economic empowerment, and restoring environments through low-cost regenerative agriculture. As a mechanism to coordinate and drive this work, it is recommended all national and donor governments in the Pacific region, including Australia, work together to develop an Economic Recovery Compact – a roadmap to rebuild the regional economy in a way that leaves no one behind. By rebuilding livelihoods, starting at the bottom of the economic pyramid, donor and national governments can increase productive capacity, broaden the consumer base, and build resilience across the market system, all while supporting those who need it most. Just as regional governments worked together to establish the Pacific Humanitarian Pathway on COVID-19, the region should again coalesce around the longer-term recovery effort – because a regional crisis like this requires a regional response. For more information, see World Vision’s report Pacific Aftershocks: Unmasking the impact of COVID-19 on lives and livelihoods in the Pacific and Timor-Leste.   This article appeared first on Devpolicy Blog (devpolicy.org), from the Development Policy Centre at The Australian National University. Jonathon Gurry is World Vision Australia’s senior policy advisor, leading policy development on livelihoods, food security and climate change. He is a former lawyer with many years of international experience in the aid and development sector. Dane Moores is the Policy Manager at World Vision Australia where he oversees policy analysis and influencing on child rights, livelihoods and food security, conflict and fragility, and First Nations policy.

In a commentary of Stephen Howes, Director of the Development Policy Center and a Professor of Economics at the Crawford School of Public Policy, shared his opinion and discussed how the June ASEAN agricultural visa announcement could develop or evolve. He noted three possibilities. First point he made is the possibility that Asian countries will by allowed to join the Pacific Seasonal Worker Program (SWP) and the Pacific Labour Scheme (PLS). Another scheme might be in place as well for Asian countries. Lastly, "existing backpacker caps for Asians to work in Australia would be increased." [1] An announcement made last August by a group of Ministers on both sides of the Coalition entails that a new Australian Agriculture visa is to be created in addition to the SWP and PLS. However, the commentary notes that "it is hard to believe that the regulations for the new visa will be in place by the end of next month." "Agriculture Minister David Littlepround highlighted the Philippines, Thailand, and Vietnam (and the UK) in his ABC interview." However, the press release only says that the Australian Agriculture visa will be open to applicants from a range of countries negotiated through bilateral agreements. No countries were mentioned. "Despite these assurances, the press release is in some ways more alarming than the initial Littleproud announcement," said Howes. Aside from the agriculture sector, the new visa covers other related industry such as the meat processing, forestry, and fishing. Administration of the new visa is to be given to the Department of Foreign Affairs and Trade (DFAT). Even with DFAT being assigned to handle the new visa, some speculate that this might pose a threat to the Pacific labour mobility in the PLS. The meat processing industry comprises 71% of the PLS jobs, while agriculture and horticulture is 21%. "If employers in these two sectors switch to the new visa PLS will collapse," according to Howes. He also points out that the SWP might also be in danger. "The risks are especially high given the press release's commitment to a 'demand-driven approach' -- the implication being that the new visa will be uncapped. The Australian Agriculture visa lacks public policy justification. All the sectors covered by it are already covered by the PLS." Timor-Leste and the Pacific island nations sends workers under the SWP and PLS, and they have to meet the demand for labour in those sectors. "If this new visa is to have a pathway to permanency built into it (something which the press release says will be considered) then so too should the PLS. And whatever safeguards are applied to the PLS should equally apply to this scheme," said Howes. ----- Reference: [1] Howes, Stephen (30 Aug. 2021). "Yesterday's Regional Visa announcement: The End of the PLS?". Post-Courier. Retrieved from - https://postcourier.com.pg/yesterdays-regional-visa-announcement-the-end-of-the-pls/ Note: The article by Stephen Howes that was published on Post-Courier first appeared on Devpolicy Blog (devpolicy.org), from the Development Policy Center at the Australian National University. ret Photo credit - https://crawford.anu.edu.au/news-events/news/5686/developing-research-centre-region

Background – Petroleum Industry in Papua New Guinea The exploration for petroleum in Papua New Guinea has a long history which dates back to early 1900s. It began with a group of Australian geologists who first came in 1913 to PNG to investigate prospects of hydrocarbon on behalf of the Australian Government. Since then exploration activities went on without commercial discoveries until 1986 when Iagifu-Hedinia well was discovered. First commercial production commenced in 1992 with Kutubu coming on production followed by Gobe and Moran PNG reached a peak production of 150,000 barrels of oil per day in 1993 but since then it has been steadily declining as a result of natural depletion of the discovered oil resources. While in search of oil large volumes of gas of commercial quantities have been discovered in the country. The gas reserves may be categorized based on three stages of maturity. Stage 1 gas include gas already in production, in particular, PNG LNG trains. State 2 of the gas include an estimated 15 tcf proposed for development. Papua LNG, P’nyang, Pasca and Stanley make up this component of gas. A further 7 tcf of mostly stranded gas fields retained under PRLs remain to be developed. This class of gas discoveries have no plan of development in the foreseeable future. In terms of proven, probable and possible (3P) gas reserves stand at 25.5 tcf while overall gas reserves potential is in order of 40 tcf. In relative terms PNG has more gas than oil. Huge gas resources are the basis for building a gas industry in PNG and the Government has long-term perspective of building a gas industry in PNG. Having regard, a number of gas development proposals have been initiated and promoted by the developers for development.  PNG now hosts a world class LNG Project – the ExxonMobil led PNG LNG Project which commenced production in May 2014. The PNG LNG Project is the single largest investment that has ever occurred in the country. Not only that but it stands as the first gas project to be developed, and it serves as a catalyst for further gas development to take place in the country. PNG LNG has to date been the major source of revenue generation, infrastructure development, employment opportunities for many Papua New Guineans, training and skills transfer, community development, among others. Among the proposals that have been looked at Papua LNG, P’nyang, Pasca, Stanley are among the proposed projects lined up for development. The country also has more than ten stranded gas fields under Petroleum Retention Licenses (PRLs). These discovered gas resources cannot be developed on standalone basis due to the nature of the volume content; insufficient for commercialisation and the gas fields are isolated meaning they sit away from any form of communication and infrastructure development. To develop them individually would be very costly and uneconomical. Papua LNG Project The Papua LNG Project has evolved from the prospecting stage, to the discovery of Elk/Antelope gas resources, to signing of the Papua LNG Gas Agreement and now to LNG development. The discovery of the Elk/Antelope gas resources which is located in the Gulf Province has given prominence to developing these gas resources in the country. The previous owner and operator InterOil proposed for a LNG project to be supported by the Elk/Antelope gas resources. Following the discovery of the gas resources several gas development schemes were announced by InterOil but none of the proposals advanced to development phase. The country’s expectations for superior benefits from developing Papua LNG Project have been high. Why wouldn’t the country aspire to greater benefits from its premier resources – the gas resources?  Such expectations have been on the back of “missed opportunities” from the first ever largest resource project – the PNG LNG Project that the country hosts. The general view among Papua New Guineans have been that any future gas resource development that followed the PNG LNG Project must generate superior benefits, higher and greater than those produced by the first LNG project. In order of the new gas projects proposed for development in the country Papua LNG has its nose in front of others. The recent signing of the Fiscal Stability Agreement re-affirms the parties’ commitment to progress the project to development stage. Fiscal Stability Agreement The companies expect the global economic environment to be right providing an economic environment conducive before they can commit to huge investments especially, investing in major resources projects. Economic conditions must be attractive enough for them to develop world class projects. The key factors such as oil price in which gas price is linked, gas markets and other conditions must be right as their movements can negatively or positively impact on return on investment. Unexpected global pandemics such as COVID 19 have devastative impacts on the petroleum industry. The petroleum industry is still trying to find its position from the impacts of the pandemic in 2020 and 2021. At national level the role of the host Government is critical in the development of key resource projects such as Papua LNG Project. The companies’ desire is to see Governments providing fiscal, legislative, policy regimes and stability for investments to take place in the country. The Fiscal Stability Agreement signed on the 9th of January 2021 between the Independent State of PNG and the Papua LNG Project Participants re-affirm the Government’s commitment that it will not temper with the fiscal terms that were agreed between the parties in the Gas Agreement executed in April 2019.  The Project Participants will make significant investments in developing the Elk/Antelope gas resources hence, they expect risk free environment. It is imperative on the part of the Government of PNG to ensure there are sufficient assurances and stability accorded to the companies during the development and operation phases of the Papua LNG Project. In this respect, the assistance and co-operation of the project host government is critical for projects to be developed.  The role of the Fiscal Stability Agreement is to provide sense of comfort and assurance on the part of the Government of PNG that it will commit to the terms agreed in the Gas Agreement and any future changes to the fiscal regime by the Government will not apply on the terms agreed for the Papua LNG Project. The Fiscal Stability Agreement is not a separate agreement from the Gas Agreement signed two years ago. It rather serves as an annexure to the Gas Agreement. The Fiscal Stability Agreement is part and parcel of the Gas Agreement. The Fiscal Stability Agreement is required to give confidence to the investors of the stability of the project.  From the perspective of the Project Participants the Fiscal Stability Agreement should provide stability, sense of security and mitigate political and fiscal risks that may distort the delivery of the project. The Elk/Antelope Gas Fields The Elk/Antelope gas fields have their origins in one of the largest prospecting areas InterOil initially applied for in the late 1990s. The maximum number of blocks an applicant can apply for a prospecting license under the Oil and Gas Act 1998 is 200 blocks which equates to 16,000 square kilometres. A block is equivalent to nine kilometres by nine kilometres so 200 blocks would aggregate to 16,00km2. The original PPL that now hosts Petroleum Retention License (PRL 15) was top filled and PPL 238 issued to InterOil in March 2003 as a consequence of the Fiscal Incentives the Somare Government introduced at the time. The incentive package was introduced to encourage and reverse the dwindling exploration sector in the country. The incentives paid off resulting in reversing the fast declining exploration sector to one of active exploration sectors in the country.  InterOil’s primary focus in Papua New Guinea was to establish an oil refinery which it was successfully awarded the first Petroleum Processing Facility License (PPFL1) to develop and operate the Napa Napa Oil Refinery. While pursuing oil refinery project InterOil decided to enter upstream exploration sector. The areas InterOil applied for were “frontier” areas, not many companies were interested in. Many oil companies concentrated their efforts on the proven oil province; further west especially in the Southern Highlands, Hela and Western Provinces. Little did they know that this area was highly prospective with chance of major gas discoveries in the country. InterOil was convinced it would discover hydrocarbon and so it did after years of active exploration work. The gas fields that underpin the Papua LNG Project sit in two gas fields namely Elk and Antelope. These gas fields were named after animals found especially in Canada since the original owners Phil Mulacek and Christian Vinson are Canadians. The Elk 1 well registered a gas discovery on 26th June 2006 in PPL 238 which later changed to PPL 476. On 01st May 2008, the Antelope 1 and Elk 4 wells registered gas discoveries in PPL 237/238 which later became PPLs 475 and 476 respectively. Subsequently, wells were drilled successfully in PPLs 237 and 238. These discoveries and further work that current Operator Total has undertaken since taking over the Elk/Antelope gas fields provide the foundation volume for the proposed Papua LNG Project. In order to confirm the discovered gas InterOil engaged resource certification companies including GLJ and Knowledge Reservoir to provide assessment of the gas resources in the Elk/Antelope fields. In 2008 and 2009 GLJ concluded that the fields combined contained more than 8 tcf (trillion cubic feet) of gas and over 100 mmbbls of condensate contingent resources. Upon receiving the reserve certification reports the Government of PNG needed second opinion so it engaged Gaffney Cline & Associates (GCA) to provide a 3rd party certification of the Elk/Antelope gas resources. The GCA report produced total 2P recoverable sales gas resources in the Elk/Antelope fields of 6.5 tcf. However, GCA indicated that the above volumes did not take into account 5% CO2, fuel and flaring so the Department of Petroleum assessed that the saleable gas resources would be about 4.85 tcf when it took these qualifications into account. It was also recommended that further appraisal wells should be drilled to ascertain full extent of the reservoir and increase the level of confidence in the resource finds. When Total took over operation of the project one of the key tasks was to work on improving the gas resources. The company undertook aggressive upstream work. The aggress efforts both the previous and the current operator have put into the upstream exploration including drilling and appraisal work programs further improved the discovered gas resources. The Gas Agreement clearly has more than the 8 tcf InterOil estimated at the time as the foundation gas underpinning the Papua LNG Project. Petroleum Retention License (PRL 15) Award The discovery of gas leading up to the declaration of location as per the requirements of the Oil and Gas Act 1998 enabled InterOil to successfully apply for a Petroleum Retention License over the blocks that contained the discovered gas resources. On 30th November 2010, InterOil was granted PRL 15 over the 9 blocks covering the Elk and Antelope gas fields. As required by the oil and gas law InterOil had submitted approved work program and expenditure proposals for implementation during the term of the PRL.  InterOil, as the holder of PRL 15 committed to implementing work programs including additional wells, seismic and geoscience studies, social mapping, social mapping and marketing studies. The intent of a Petroleum Retention Licence is for the license holder to retain the discovered gas while further work is undertaken for commercialisation of the discovered resources. In assessing an application for a PRL there must be an economics assessment justifying that the gas discovery is not commercial to develop thus it should be retained under a PRL requiring further commercialisation studies to be undertaken. It is to be noted that PRL 15 was granted having passed the commerciality test. The PRL provided the impetus to the license holder to retain the asset and further work continued. Concepts for Developing of Elk/Antelope Gas Resources The gas resources that InterOil discovered provide the resource base for development. InterOil since the discovery of the gas had started considering a number of development schemes to develop the Elk/Antelope gas. This led to the signing of the Project Agreement which was signed on 23rd December 2009 between the Independent State of Papua New Guinea and LNGL (Liquid Niugini Gas Limited). Under the agreement it was agreed that LNGL and InterOil would develop a 2 train 7.6 to 10.6 mtpa capacity LNG project. The term of the Project Agreement was tied to the term of the Petroleum Development License (“PDL”), which is 25 years plus 20 years extension of the license. The Project Agreement, amongst other things, set out the fiscal terms to apply to the project.  In summary, the key aspects of the project described in the Project Agreement constitute the following: To be a World Class Project (project size and scope of international scale and quality); To produce LNG using internationally recognised technology; To be operated by internationally recognised and reputable operator experienced in operating LNG liquefaction facilities and assets similar in size, scale and nature of the Project Assets  To be located at, about or near the InterOil refinery, Napa Napa, Port Moresby or at such other location, provided that the State has approved such other location in writing; and To have a manufacturing capacity of between 7.6 million and 10.6 million tons of LNG per annum.  It was clear at the time that the intention was for this project to match the ExxonMobil-led PNG LNG Project in terms of scale, performance and quality and to be operated by a highly experienced, internationally reputable operator. On account of the similarity of the two LNG projects it was determined that the State would offer LNGL Project bag of fiscal terms similar to the ones offered to the PNG LNG Project. However, for several years since the signing of the Gas Agreement InterOil did not secure a partner it was looking for. In fact, there were parties InterOil approached from mid-2009 with the objective of securing an operator but these efforts were not successful.  The delay was a cause for concern for the Government of Papua New Guinea. For example, the Minister for Petroleum and Energy and Secretary of the Department at the time sought clarification on the development of the project and the status on securing partner/operator of the project.  While search for a reputable partner to develop the project was going on announcements relating to the development of the project of different character in the Gulf Province were made. On 15th April 2010, InterOil announced that it would develop a condensate stripping project together with Mitsui & Co. Ltd of Japan using the Elk/Antelope gas. On the 28th of September 2010 it also announced that it would pursue small LNG projects with capacities of 2 to 3 mpta. Subsequently, InterOil announced smaller project concepts. InterOil further proposed a 50/50 gas development split with the State where it would acquire additional 27.5% interests on commercial terms, in addition to its legal right to a 22.5% participation interest in the project. As can be noted, the project had deviated from the original project concept outlined in the 2009 Gas Agreement largely owing to the fact that the project development concepts announced by InterOil were of small scale. None of the proposed development concepts were able to match the project concept described in the 2009 Gas Agreement. InterOil and its partner LNGL had executed Heads of Agreement with Energy World Corporation Limited (“EWC”) and separately with FLEX LNG Limited and Samsung Heavy Industries for development of a floating LNG plant. The proposal comprised the following features: An initial land-based LNG plant of 2 mtpa comprising four trains of 0.5 mtpa; Additional trains of 2 mtpa to be added each year until a total capacity of 8 mtpa is achieved;  A fixed floating LNG plant of 2 mtpa; and A condensate stripping plant. However, none of these concepts were translated into gas projects. The same story remained throughout the period that InterOil had promoted the development of the Elk/Antelope gas resources since the signing of the Gas Agreement in 2009 until Total; the French oil giant appeared on the scene.   The Entry of Total SA as Operator of the Elk/Antelope (Papua LNG) Project The efforts that InterOil had put in since the signing of the Gas Agreement finally paid off when a new partner Total was selected from among the oil majors known to many Papua New Guineans including ExxonMobil, Chevron, Shell, British Petroleum (BP) as well as other familiar names in PNG such as Oil Search, Talisman Energy, Horizon Oil and Santos. The new entrant Total was a new face in PNG.  To be appointed a partner in the country’s Second LNG Project, especially to a company not familiar with PNG this French National Oil Company brought a new perspective to developing the country’s gas resources. Many of the people who followed InterOil’s final countdown of selecting a partner were most probably expecting some familiar names in PNG.  Nevertheless, the key thing to note is that agreement between Total and InterOil followed an extensive international competitive bidding and evaluation process for development of InterOil’s interests in Papua New Guinea that InterOil had promoted since 2009. Under the agreement Total would lead the construction of the project and operate the proposed integrated LNG project. The parties further agreed that a final investment decision, reserves certification, basis of design and front-end engineering and design would follow. Total in its own right is an undisputed oil major and LNG player but new to this part of the world as confirmed to Business Advantage PNG by Total’s Managing Director in PNG, Philippe Blanchard; “When you are a French person like me, coming to work in PNG, it is like going to the other side of earth, working in an environment that has nothing in common with Europe. The Asia-Pacific region has a completely different mindset—challenges everywhere and, personally speaking, many things to discover. It’s a complete change to what I have been accustomed to in Europe or even Africa. It is really exciting”. The company undoubtedly had set its plan to develop Elk/Antelope gas resources and so it successfully won the operatorship as well as acquisition of a major stake in the project. However, the transition was not as straight forward as it desired. Total had to overcome legal challenge from Oil Search Limited which claimed that the PNG based company had transacted a deal with InterOil and therefore had pre-emptive rights. The arbitration however found that this was not the case. The commitment by Total to deliver the Papua LNG Project was demonstrated at the outset. A few months after its entry into PNG the Total’s Managing Director informed Business Advantage PNG this; “We are experienced in LNG. We are present in the whole value-added chain of PNG projects from upstream assets, to building LNG trains and trading LNG products. We are the second actor after Shell in this business. We will take advantage of the experience and knowledge of all our partners to be able to deliver together a good project. So we want to put this arbitration period behind us and we want to fully restore the relationship with our co-venturers. We believe there is plenty to do to deliver the project and we need the energy of everybody”. Mr. Philippe Blanchard further added that; “We are committed to the project. We have already made a big investment before we entered the license. It is clear our interest is to deliver the project”. It became apparent that the French oil major was destined to make an unprecedented impact on the country’s petroleum resources sector. The company was particularly focused on delivering the Papua LNG Project. It was obvious from the outset of the takeover that the Elk/Antelope is a significant project in Total’s global portfolio and clearly this asset in Papua New Guinea provides an opportunity to grow and expand its business in the Asia-Pacific region. The acquisition of an interest in the Elk/Antelope project was a significant investment in large discovered resources which provides exciting opportunity for the French company to develop a new gas production and liquefaction hub in this part of the world. Clearly, the PNG asset added value to its long term player as a LNG player on the global stage. Total’s acquisition of PNG asset did not stop at PRL 15. The company also had an option to take an interest in all of InterOil’s exploration leases in Papua New Guinea including PPLs 236, 237 and 238 which InterOil continued to operate at the time. The understanding between Total and InterOil was moreover to explore other business opportunities both in Papua New Guinea and elsewhere in the Asia Pacific region. On project front Total quickly established a strong relationship with its joint venturers and strong support from the Papua New Guinea Government. This made Total settle in this part of the world where it hadn’t made much presence, and looked forward to developing the LNG project. In the ensuing years that followed since its entry into the country’s oil and gas sector Total took over the operatorship of the Papua LNG Project. It also brokered formidable Joint Venture partnership with the existing players in PNG including ExxonMobil and Oil Search. Total has also worked with PNG’s National Oil Company – Kumul Petroleum in view of the State’s legal right to participate in the project. The State participation is formally exercised at the time of PDL award but it is important to establish some level of relationship with a key national partner Kumul Petroleum. The NOC, using its network and connection with the Government has played key role in progressing the Papua LNG Project to date. To successfully pull off major agreements such as the 2019 Gas Agreement and the Fiscal Stability Agreement Kumul Petroleum has played key role between the Project Participants and the Government in order for the parties to agree and execute such complex and important agreements. The recently signed Fiscal Stability Agreement now paves way for a key milestone to be undertaken which is FEED (Front-End Engineering and Design Studies). FEED normally take up to 18 months but its completion will lead to developing Papua LNG Project. Further work included social mapping, landowner identification, environmental impact assessment, license and administration, among others. This will take the project to Project Sanction and reaching FID (Final Investment Decision).  Project Benefits The recent execution of the Fiscal Stability Agreement signals that Papua New Guinea will host its second LNG project. This will be a world class LNG Project staged in the country and based on its magnitude the project is expected to generate multiple benefits, both direct and indirect. The direct benefits will be generated via the fiscal terms that have been negotiated in the Papua LNG Gas Agreement which was executed between the PNG State and the Total led Project Participants in April 2019. The Fiscal Stability Agreement signed in January 2021 between the parties confirms and provide the stability over the fiscal terms. In Papua New Guinea the legislated fiscal regime for petroleum projects has been the basis for oil and gas investment in the country. The fiscal regime has also undergone numerous adjustments over the years. Nevertheless, the core elements remain to this point. The key features include production-based levies, the taxation of company profits and an additional profits tax that kicks in only when profits exceed a pre-determined level, particularly in the year in which the accumulated value of “net cash receipts” becomes positive and State participation. The new main features that have been introduced in the Papua LNG Gas Agreement include production levy and up to 5% DMO.  The headline terms of the Standard regime are set out in the table below: Inflation (CPI)         2% Depreciation rate      25% Royalty                   2% Development Levy      2% Corporate Tax               30% Dividend withholding tax 15% Import Duty            10% Export Tax              10% State Participation         22.5% Additional Profit Tax: Tier 1 Uplift          17.5% Tier 1 Rate            7.5% Tier 2 Uplift          20% Tier 2 Rate            10%   The main fiscal terms that make up the Standard terms comprises Corporate Tax, Royalty, Development Levy, Additional Profit Tax, Dividend Withholding Tax, Import Duty Tax, Export Duty and State Participation. Despite the fact that Standard Fiscal Terms applicable to gas operations are legislated or defined in the Government policies each term is negotiated per project. The companies prefer exemptions and incentives awarded to them. The PNG LNG Project has an agreed set of fiscal terms which is applicable to the project. The Papua LNG Project will have the fiscal terms that were negotiated and agreed by the parties. Future gas projects will have specific fiscal terms negotiated and agreed between the State and the Project Participants. Announcements made by the Government and the Project Participants following the signing of the Papua LNG Gas Agreement indicate that the parties have agreed on fiscal terms that may be best summarized as follows; Tax on integrated project basis, not segmented basis as the Papua LNG Project is envisaged to be development on the integrated basis The fiscal terms apply to all PRL 15 gas, Main fiscal terms including Corporate Tax, Royalty, Development Levy and APT to apply. But Import/Export taxes, Withholding taxes exempted as well as GST zero rated New fiscal devices introduced in the Papua LNG Project include Production Levy and DMO provision. State Participation at 22.5% Direct project benefits to the State will be generated via the fiscal terms that have been agreed between the State and the Project Participants. However, as regards indirect benefits to the State there aren’t set formula based on which benefits from the project would be generated. Benefits such as schools, health facilities, roads, community projects, infrastructure projects and pin off business activities are counted as indirect benefits. The fact is that the indirect benefits do not have defined formula in which the benefits will be determined. Important Government policies in relation to indirect benefits are not defined. Recently, the Government has attempted to develop policies around Domestic Market Obligation (DMO), National Content Policy and Third Party Access but these policies are yet to be developed and approved by the Government. Given the obvious absence of fully defined policies it is impossible to quantify the indirect benefits to the State. This remains a grey area the Government must work harder. One way the Government of PNG can benefit more from its resources development is to negotiate hard on the indirect benefits. This is where National Content policy becomes so critical; essentially this may ascertain how much of the benefits would benefit the country. It is to be noted that what is not known is the indirect benefits expected to be generated by the project. It is difficult and more challenging to predict indirect benefits especially, before the project has been developed. Clearly defined Government policies in relation to the indirect benefits are needed to ensure the country benefits from its resource development. For example, the National Content Policy should define and state how much of the capital expenditure during construction should be spent in the country. There should be similar policy in relation to the ongoing operating expenses. The ad hoc handling of the indirect benefits to date has left the country missing on important benefits that emanates from resource project development. Project Benefit Projections On comparative basis the projected direct benefits from Papua LNG may be compared with two other petroleum projects in the country. These include Oil Projects and PNG LNG Project. Oil production to end of 2019 from all PNG oil fields including Kutubu, Gobe and Moran was estimated at more than 531 million barrels (Mbbl) of oil. Assuming at an average oil price of $50 per barrel oil has generated an estimated US$20 billion plus on gross revenue basis. Kutubu attracted approximately US$1 billion in capital expenditure for development plus US$350 million in exploration cost. This was the major investment undertaken at the time to develop the major oil project in Papua New Guinea. The PNG LNG Project cost US$19 billion in capital expenditure. PNG LNG had a foundation volume of 6.9 tcf. Assuming that LNG is sold at an average gas price of US$12/mmbtu this will generate around US$80 billion in gross revenues. However, the project has been subject of recent down turn in the global market due to global pandemic. It is now general knowledge that the gas price has been rock bottom in 2020. The operating cost and other factors do impact on the overall project revenues though this may be offset by increased production. PNG LNG Project connects several PDLs and covers approximately 700 kilometres of pipeline infrastructure from the upstream gas fields to the LNG plant site near Port Moresby. The project remains the country’s largest investment ever undertaken in the country. PNG LNG Project since coming on production in May 2014 has been the source of revenue generation, employment, infrastructure development, community development and host of other benefits to the country. Relativity to PNG LNG the proposed Papua LNG is expected to cost less.  Papua LNG project deviates from the first LNG project on many fronts. The ELK/Antelope gas will be extracted from a single PDL and the pipeline infrastructure will cover shorter distance from the upstream to the LNG processing plant site. Based on public information Papua LNG is anticipated to cost over US$12 billion and the foundation volume is estimated higher by about 3 tcf relativity to PNG LNG’s foundation volume. Assuming that gas price averages US$12/mmbtu the Papua LNG could generate over US$100 billion in gross revenue. Comparatively, Papua LNG will kick start as low cost and high volume project. Assuming that gas price averages above US$10/mmbtu Papua LNG is destined to be a high yielding project.  However, Papua LNG Project is not immune to the unpredictable down turn in gas prices, high operating cost and other factors that may impact negatively on the revenue generation. The indications are that revenue anticipated from Papua LNG will be higher.  This means that more revenue is envisaged for the Government. Papua LNG is a key project in terms of revenue generation and so it must be supported by the Government. The Government’s undivided support for the project has already been demonstrated in delivering two pillar agreements: Papua LNG Gas Agreement and the Fiscal Stability Agreement. But that is not all. The Government will issue the licenses at an appropriate time. This will depend on Total delivering PDL requirements which include FEED, Landowner Identification and Social Mapping, Environmental Assessment, among others. Among the oil producing countries PNG has been recognised as oil producer since 1992. In 2014, PNG entered the exclusive club of LNG producers in the world. The project serves as a catalyst for future gas development in the country. More gas development means more benefits to the country.  However, the critical point to state here is this. As a country, how has PNG featured in managing huge benefits from oil projects and now PNG LNG? Have these benefits actually translated into improving the lives of the people, especially the rural population? Prior to Papua LNG commencing production in the next 5/6 years, P’nyang and others reach development stage the Government’s priorities and policies must be set differently from what has been the norm, ultimately targeted at improving the lives of the people and advancing the country forward.

By Roger Kewa Avinaga Like any other industries that have been impacted by the COVID-19 in 2020, the mining industry has been impacted by the pandemic. The industry has been confronted with numerous challenges. The operations of the mines shut down, some mines have suspended or scaled down operations while others have gone into isolation mode. On the commodity markets, like it has been for many commodities around the world the supply sources have been affected and also the demand for this commodity has decreased. While some mines have resumed operations they have done so under “new normal”. As a result of all of these, employees and dependents have been affected as the sources of survival for many have been cut off as a because of the mine shutdowns, suspension or scaled down of mine activities. COVID-19 clearly caught the world by surprise. No one predicted the pandemic of such a magnitude would impact the world. In any mine operations identification of risks and risk management is part and parcel of operations but who knows how many mining companies actually had COVID-19 in their risks profile and management. The real story is the pandemic caught everyone by surprise, no doubt about it. The fact remains – COVID-19 has left both short term and long terms impacts on the mining industry. It will require new sets of measures to respond to the impacts left by the pandemic. It will require the efforts of the various parties including the government, companies, investors and other parties to address the impacts left by the pandemic.THE MINING INDUSTRY IN PAPUA NEW GUINEAThe mining industry in PNG has been in existence for many years. It has become a pillar for the country’s economy, source of revenues, infrastructure development, development of rural communities, employment opportunities, among others. The country extracts a wide variety of metals, which is developed and exported overseas. The most common metals produced in Papua New Guinea include copper, gold and silver. Interestingly, some of the rare metals have been discovered and mined in PNG such as nickel, cobalt, chromium, iron and platinum. Active exploration is going on in parts of the country which has the potential for further discoveries of commercial quantities. However, many parts of the country are complicated by the rough and rugged terrain which makes exploration for minerals difficult. The harsh environment complicates the setting up of the mine sites as well as establishing infrastructure for developing the resources. OPERATING MINES IN PAPUA NEW GUINEAPNG has a well established mining industry on account of several world class mines operating in the country and mining dates back to 1920s and 1930s. Certain mines such as Misima Mine has exhausted its production life span. The Panguna Mine in the Autonomous Region of Bougainville (AROB) has been closed down since the start of civil war more than two decades ago. The mine is yet to be re-opened. Several operating mines in PNG include the following;(a) Lihir Gold MineLihir Gold Mine has been producing gold and it is the country’s largest gold producer. The mine is located in New Island Province and is operated by Australian gold miner Newcrest Mining Limited having taken over in 2010 at the estimated cost of $9 billion. Employing approximately 5,000 employees the mine is a source of employment, revenue, infrastructure development and community development, among others. The mine life expected is 20 plus years. In December 2019, the Lihir mine reported estimated reserves containing 320Mt of combined proven and probable reserves grading at 2.3g/ of gold (Au), with in-situ gold of 23Moz. It has been further reported that in June 2019 Lihir mine achieved the target of 15Mtpa. The mine had a production of 933,000oz in 2019 and 187,245oz in the March 2020 quarter. The Lihir Gold Mine remains an important producing mine for Papua New Guinea.(b) Ramu Nickel-Cobalt MineThe Ramu NiCo mine produces a rare metal called nickel-cobalt. The project first commenced production in 2012 with a designed capacity of 32,000 tonnes per annum for nickel and 3,200 tonnes per annum for cobalt. The mine is operated by a Chinese company MCC (Metallurgical Corporation of China). The project was developed with a total investment cost of US$2 billion. The mine is a source of revenue, employment and revenue generation for the country. However, the mine has been subject to environmental concern caused by dumping of mine waste into the river systems in the area. (c) Porgera Gold MineThe Porgera Mine is located in Enga Province. The mine produces gold and silver producing an estimated half a million ounces of gold annually. The Porgera mine before the takeover by the Government in 2019 was owned 95% by Canadian company Barrick and Chinese company Zijin. The 5% has been owned by the Enga Provincial Government.However, on the expiration of the Special Mining Lease in 2019 the Marape led Government decided not to renew the license, which led to the ceasing of the mine’s operation. Currently, the mine has been closed down causing unemployment, ceasing revenue generation, among others. COVID-19 further prolonged the shut down of the mine. In an unprecedented move, the Special Mining Lease was then awarded to the State-Owned Enterprise (SOE) Kumul Minerals Holdings Limited (KMHL) by the regulator - Mineral Resources Authority (MRA). This has caused further issues for Barrick and some factions of the landowners. Also, across the globe, the Government’s action has sent wrong signals that the Government has taken over the mine. The investors will clearly think twice before they can invest in the country.However, the Marape administration maintains that its actions are for the interests of greater public ownership of the mines as well as oil and gas resources development. Disappointed by the Government’s decisions and actions the gold mine operator Barrick has taken the State to court over its actions. Whilst pending the outcome of the court decisions, and on a recent note, meetings between Prime Minister James Marape and the boss of Barrick has taken place signalling way forward for the mine. However, the details of getting the mine re-opened will be finalised between various parties including Barrick, Government, Kumul Minerals, Landowners/Enga Provincial Government, etc. It will be interesting to see what transpires from this in relation to equity split, operatorship, etc. The Porgera Mine is a source of employment for many and its closure has impacted the employees and their dependents. The sooner the parties resolve the issues and re-open the mine the better it is for all parties and the country as a whole. (d) OK Tedi MineThe OK Tedi Gold Mine was opened in 1982 by the previous owner BHP of Australia. The mine produces three of the common metals including copper, gold and silver. The Mine is located in the Star Mountains of the Western Province. The mine is operated by OK Tedi Mining Limited and the mine is owned 100% by the State, having taken over the mine in 2013 from the previous owner. The production life of the mine was estimated to end in 2025. However, further work is also carried out on resources upgrade which could expand the mine life further. The mine was previously owned and operated by BHP Billiton, an Australia mining giant. However, due to environmental concerns over the Fly River systems the company left and handed over the mine to the State as a “compensation package”. BHP may have escaped legal case which could have cost the company more for environmental damages. BHP would have been subjected to serious legal challenge for the mining giant. The company at the time channelled the mine waste directly into the river systems that run into OK Tedi and Fly River.Since the take over by the Government the mine is a source of infrastructure development, revenues, employment, community development and social development especially, in the project host Western Province. In 2002, BHP Billiton withdrew from the mine and established development fund of the benefits of the people of Papua New Guinea. This fund is called PNG Sustainable Development Program Limited. This fund has become subject of dispute between the former Prime Minister Peter O’Neill and the Chairman of PNG Sustainable Mekere Morauta, especially over the ownership of the fund.The OK Tedi mine is currently placed under the State-Owned Enterprise Kumul Minerals Holdings Limited.(e) Hiden Valley MineThis mine is owned 100% and operated by the South African mining company Harmony Gold Mining Company Limited which also owns 50% of the upcoming Wafi-Golpu mining project. The Hiden Valley gold project located in Morobe Province started first gold production in 2009. Since then it has been producing gold and silver. By comparison, this mine is a small mine in relation to Porgera, Lihir and OK Tedi but the mine is a source of revenue generation, employment, infrastructure development and community development.(f) Kainantu Gold MineThe Kainantu mine is owned by K92 Mining which produces gold. This mine was previously owned by Highlands Pacific and Barrick Gold from 2006 to 2009. This project has been in operation since 2006. This mine is located in Kainantu District of the Eastern Highlands Province. The new operator of the Kainantu Mine has been responsible for recruiting 800 employees and also serves as a source of revenue and infrastructure development.It has been reported that the mine produces higher gold grades resulting in strong financial results, including record net cash and throughput following the commissioning of stage 2 plant expansion. In its quarterly report, the company reported that a quarterly revenue of US$35.6 million, which is a 70% increase from Q3 2019. A record tonnage of 64,702 tonnes treated which is a 102% increase from Q3 2019.The mine has put in place a proactive and focused management of COVID-19 and continues to operate the mine and also has strong preventive and response plans.(g) Simberi MineThe New Ireland Province does not only host the Lihir Gold Mine but also host Simberi Gold Mine. The mine is operated by St Barbara Limited through a Mining Lease (ML 136) which covers most of the eastern half of Simeri Island. Compared to Lihir Simberi is not a large mine but it is able to be the sources of revenues, employment opportunities, rural development especially in the northernmost islands of New Ireland. The mine focuses on epithermal gold in oxide and sulphide deposits. It has been reported that the mine life of Simeri mine has been extended to 2035 and it is an open-pit mine. IMPACTS OF COVID-19 ON MINING OPERATIONS AND THE ECONOMY IN PAPUA NEW GUINEAThe COVID-19 measures that were applied in the country during the height of the pandemic including the State of Emergy (SOE), social distancing, limited movements, and other restrictions imposed to minimise the spread of pandemic clearly impacted the operations of the mine operations and activities in Papua New Guinea. Given the country’s connectivity to the outside world, there is no way PNG would have avoided contracting COVID-19. In fact, the first recorded case in Papua New Guinea was an employee of a mine. The OK Tedi Mine closed down when it reported seven COVID-19 cases at the mine site. The Lihir Gold Mine also had one COVID-19 case. The OK Tedi mine operation was shut down as a result of its employees contracting the virus. Financially, the closure was anticipated to cost the mine an estimated K100 million. The mine employees were laid off as a consequence. However, the operation resumed following weeks of the mine shut down. The OK Tedi Mining Limited announced a temporary closure of the mine. It announced a 14-day suspension of the operations while contact tracing and isolation procedures with the intent to minimise any spread of the infractions. Operations resumed after it had reached a satisfactory stage. The Lihir Gold Mine did not shut down its operations but necessary measures were employed by the mine to isolate the COVID-19 patient with appropriate restrictions applied at the mine site. OK Tedi, Lihir, other mines as well as the PNG Chamber of Mines and Petroleum maintained a dialogue with the Government team on COVID-19 to ensure there were minimum disruptions to the mine operations and at the same ensure the health, well being and safety of the industry employees was of paramount importance. This included putting measures to manage and minimise the spread of the virus and the negative impact the pandemic would have on the mine operations, its employees as well as surrounding communities. It has become common knowledge that COVID-19 caught the world by surprise. No one predicted that such a deadly pandemic would hit the globe by storm and have a devastative impact on the lives of the people. The pandemic impacted the global economies, businesses, societies, governments and the lives of the people. On account of our connectivity to the world PNG became COVID-19 impacted country. The Government of PNG quickly responded to the pandemic and put in place a strategic response plan including making finance available to address the pandemic. The spread of COVID-19 may have been contained in Papua New Guinea but this is not to say that the virus is not capable of spreading. The Government of PNG through the Controller encourages everyone in the country to continue to observe the COVID-19 measures and live within the “new normal” limits. The operating mines have also adopted these measures and continue to observe and adhere to these restrictions. While the search for a cure is on, restrictions have become normal. The COVID-19 has clearly left a lasting impact on the operations of the mines as well as on the exploration sector. The closure of the Porgera Gold Mine not related to the pandemic but the closure has not helped the mining industry in the country causing employment issues, reduced revenues to the country, among others. The closure of the mine has also impacted on the mining sector in the country. The known COVID-19 reported being over 600 and 7 deads in the country as well as the mines, especially OK Tedi and Lihir as they reported cases of COVID-19. It makes sense for the mines to adhere to restrictions so that the virus does not spread further.The Chamber of Mines and Petroleum which represent the industry is working closely with the PNG Government to ensure the impact of COVID-19 does not prolong for a very long time as this will have devastative impacts on the mining sector in the country. It is a fact that the mining industry makes a significant contribution to State revenues in PNG. The industry also contributes to infrastructure development, law and order, health, agriculture, etc. It is critical that the virus is minimised from spreading further. As reported by the World Bank, PNG’s economy has also been hard hit by the pandemic due to weaker demand and less favourable terms of trade. That is why the measures outlined and emphasised by the Government to contain the spread of the virus is strictly adhered to especially at workplaces such as the mines. The country has been faced with a situation where the economy has been weakened and clearly affected commodity prices. Direct results of this would include economic contraction, wider financing gaps, higher unemployment and cause for poverty increase. The mines play a significant role in the economy of the country. Any shutdowns of the mine operations due to the spread of the virus would have negative impacts hence, it is quite critical for the mines to adhere to the COVID-19 preventive measures until the country is pandemic free. OUTLOOKBoth the COVID-19 and the closure of the Porgera mine have brought about negative impacts on the mine operations and activities of the mines. It has also impacted the health, safety and well being of the mine employees. The revenue sources of the country have also been impacted. As far as the outlook is concerned the impacts of the pandemic has painted a gloomy picture. What measures could be considered to improve the mining industry and generally the country’s economy? There may be certain measures which may be considered to address the impacts of COVID-19 but discussed below is one measure that could bring respectability to the mining industry in Papua New Guinea. That is the development of the upcoming mining projects;(A) DEVELOPING THE EMERGING MINESSeveral new world class mining projects have been proposed for development for a number of years now but these have yet to reach the actual development stage. Each of the proposals has been faced with specific challenges. The recent pandemic, however, cut across all of the proposed mines. It is also important to note that PNG has not developed a world class mine in the past twenty years or so. The current operating mines such as OK Tedi’s production life span may be less than ten years which raises the need for new mines to be developed to ensure continuity of revenue generation, employment and other benefits the mines generate. This would balance off employment shortfalls, infrastructure development, revenue generation, rural development, among other benefits development of mines have brought to the country. To maintain these benefits new mines need to be developed sooner than later. There are three emerging mines that come under this category;a) Wafi-GolpuThe Wafi/ Golpu Gold-Copper Project is situated 60 km SW of Lae and NE of Hidden Valley. It is held under four contiguous licenses covering 996 km2. The project is owned by Harmony Gold, a South Africa Mining Company and Newcrest Limited, an Australian based company with a 50/50 Joint Venture. Exploration activity to date has shown that the Wafi-Golpu tenements host one of the highest grade porphyry copper systems in south-east Asia (the Golpu deposit), comparable with other world class systems such as Ok Tedi and Bougainville, located also in Papua New Guinea.The prospect comprises a complex hydrothermal system that contains two separate ore systems: the Wafi epithermal gold deposit and the Golpu porphyry copper/gold deposit which are located adjacent to each other.In 2012, the project had Mineral Resources estimated to contain 28.5 million ounces of gold, 9.1 million tonnes of copper and 50.6 million ounces of silver. This includes Ore Reserves for the Golpu deposit estimated to contain 12.4 million ounces of gold, 5.4 million tonnes of copper and 19.7 million ounces of silver. Further work has been undertaken by the JV with the aim of increasing the resources.Location of Wafi-Golpu ProjectThe Wafi-Golpu Joint Venture completed its pre-feasibility study in October 2007 which enabled technical feasibility and economical potential analysis. The Definitive Feasibility Study (DFS) has also been worked on to confirm the viability of the project. The JV is considering developing the mine which includes upgrading existing ports, concentrates pumped in slurry to facilities in Lae and filtered for shipping, mine water being a major part of the slurry supply to minimise cost, power from Hidden valley and building a new road from Wamit Village to the mine site. The Government of PNG and the Wafi-Golpu Joint Venture signed a Memorandum of Understanding (MOU) in 2018 which provides the basic terms that may constitute the negotiation of the Mining Agreement (Mining Contract) between the State and the developer for developing Wafi-Golpu resources. The State has said that it will participate in the project. Under the law, the State will acquire 30% equity in the project. The State interest in the mining project will be held by the newly resurrected State Owned Enterprise (SOE) Kumul Minerals Holdings Limited.The Minister for Environment in November 2020 issued the most important permit – the Environmental Permit to the developer, signalling the development of the project. The Marape led Government has also committed to issuing the Special Mining Lease (SML) to the developer so it won’t be long the SML will be awarded for development. As publicly stated in various sources, the estimated capital cost is approximately US$5 billion and the State’s 30% share of the development cost would be approximately US$1.5 billion. b) Frieda River Copper/Gold ProjectFrieda River Copper/Gold project is being promoted by the current owner and operator PanAust with a view to having the first production in the years ahead. This project is owned 80% by PanAust and 20% owned by Highlands Pacific. The project has copper and gold with estimated reserves of 12.9 million tones of copper and 20 million ounces of gold. Frieda River is one of the three major world-class potential mining developments proposed for development in the country. The project is comprised of the Nena, Horse/Ival/Trukai and Koki deposits with as estimated overall resources of 2,090 million tonnes of ore, at grades of 0.45% copper 0.22g/t gold and 0.7g/t silver, using cut-off grade of 0.2% copper. PanAust has estimated the cost of building the Frieda River project over US$5 billion. Once the project is developed, Frieda River is projected to produce 204,000 metric tons of copper and 305,000 ounces of gold over 20-year mine life. The Frieda River project is a world class mine in Papua New Guinea and when developed it is anticipated to generate immense benefits to the country. However, there is a critical issue that must be addressed up front by the developer before the project can reach any stage of development. There are already environmental concerns raised by various parties. The reason is that the mine development is likely to impact on the Sepik River systems and the livelihood of the people and so how the environmental issue will be managed will be critical for the development of the mine. The environmental issue must be addressed up front by the developer and the Government prior to the development of the project. PanAust, the developer has submitted to CEPA environment impact assessment report and also stated that the company is committed to dealing with the project impacted landowners.c) Yandera Copper Mining ProjectYandera Copper project is another emerging mining project in the country. The developer of the Yandera resources is a Canadian based mining company Era Resource which changed its name from Marengo Mining Limited. This company has been working towards seeking a Mining Lease for the development of Yandera. Yandera is a copper, molybdenum and gold mining project which is being promoted by the developer. The mine is located in Madang Province, in an area regarded as mineral rich in copper and cold belt prospects. Era Resource has in the past engaged industry consultants such as Minerals Industry Consultants, Ravengate to undertake JORC. It has been reported that the operator has already drilled holes resulting in 630 million tonnes of measured and undated resource and 117 million tonnes of inferred resources. The Technical Report (Updated Resource Estimate) of February 2017 shows that the measured and indicated minerals resources deposit is approximately 728 Mt at the grade of 0.39% CuEq. The resource is reported within a potentially mineable open pit configuration. Of the resources, approximately 8% of the tonnes reside in oxide where Cu is potentially recoverable by flotation. The majority of the resource is in sulphide, recoverable by conventional flotation to produce a concentrate. The proposed mine has faced a number of challenges. The first issues faced is the power supply to the project site to operate the project. Various options have been considered for power supply to the mine. In terms of the mine tailings Era Resource previously planned to be managed by deep sea tailings placement but since 2013 the plan has changed. The new plan is to develop its own dam for managing tailings released from the mine operation. Like Wafi-Golpu and Frieda River Yandera is an important project for the country. The Government will provide similar support to this project if the Era Resource proceeds to a more definitive stage of developing the project. The development of Yandera can impact on the country’s economy and generate immense benefits to the country.(d) Solwara 1 ProjectThe Solwara-1 Project was among the emerging projects having secured a Mining Lease and completed technical development work in 2012. This project has been operated by Nautilus Limited. Its partner Eda Kopa (Petromin PNG Holdings) raised K375 million ($121M) on the back of State Guarantee for investment in the project but the operator failed to secure its share of funding to proceed with the development of the first ever undersea bed mining project. In 2007, Nautilus announced Canadian National Instrument 43-101 compliant resource estimate for the Solwara 1 Project. The resulting high grade copper-gold resource was the world's first Seafloor Massive Sulphide ("SMS") resource statement. In 2010/11, further drilling was conducted at Solwara 1 resulting in an increase in the resource base. Results of the updated resource are as follows:Indicated Mineral Resource: 1,030kt @ 7.2% Cu, 5.0 g/t Au, 23 g/t Ag, 0.4 % Zn; andInferred Mineral Resource: 1,540kt @ 8.1 % Cu, 6.4 g/t Au, 34 g/t Ag, 0.9% ZnThe investment in the project has, however, become a liability to the State since the project has been stalled. The project has faced a number of difficult challenges. The Solwara 1 project has been stalled largely due to the environmental, socio and economic risks associated with seabed mining which necessitated the imposition of the moratorium. The project has been suspended and will not be developed in the next ten years or so. The Solwara 1 project which has been planned to mine mineral rich hydrothermal vents, formed by plumes of hot acid, mineral rich water on the floor of the Bismarck Sea. However, the project has been confronted with fierce community resistance, legal challenges and continued funding difficulties. Deep sea bed mining has been proven contentious wherever it has been proposed and trialled across the world and Solwara 1 project proposal faces the same reaction from different stakeholders. The technology proposed for development is also untested and tried posing more risks to marine life and the environment. (d) Other Emerging MinesApart from the major emerging projects, several small mines have been proposed for development in Papua New Guinea. The proposed mines which are at various stages of exploration/development include the following;Woodlark Island Gold Project - Kula Gold Limited is focused on the strategic development of its 100%-owned Woodlark Island Gold Project located 600 kilometers east of Port Moresby in Papua New Guinea. Crater Gold Mining Limited has two projects in Papua New Guinea including Crater Mountains and Fergusson Island. The flagship Crater Mountain Project is a potential multi million ounce gold deposits located in the Eastern Highlands of PNG. Significant gold mineralization has been discovered on the surface and at depth through drilling. The granting of the Mining Lease is a watershed milestone for the Company as it transit from developer to gold producer.Mt Kare Mining Project is 100% owned and operated by Indochine Mining Limited which is ASX and POMSoX listed company. The company is focused on near-term, high margin, gold production of c.200, 000 oz p.a. at 10 grams/tonne with cash costs expected to be among the lowest in the industry. Indochine is initially targeting high grade zones with +1 million ounces of 10 grams/tonne in 2014, expanding the 2.1 million ounce resource.(B) Mining Agreements/ContractsBeginning with the Wafi-Golpu project the State must initiate discussion and negotiate mining agreements with the respective developers of the mines. Central to this would be fiscal terms the parties need to negotiate for each project. The mining sector as discussed above has already been impacted by the pandemic and the company now need acceptable fiscal terms to develop the projects. (C) Mining LegislationNew Mining Legislation has been around for some time. However, in June 2020 the Government introduced a set of amendments to the mining law (Mining Act 1992) which lacked consultation with the industry. The industry representative PNG Chamber of Mines and Petroleum expressed these amendments as “surprise” meaning the industry was not consulted by the Government. To move the mining industry forward it requires cooperation from all the parties including companies, investors, government and landowners. When there is a lack of consultations some parties would express disappointments. In light of the global efforts to address the COVID-19 and its impacts on the mining sector, every stakeholder’s input in the legislative changes is essential not only for the mining sector but also for the country as a whole.

Does it make Economic Sense for PNG to Continue Imposing this Windfall Tax on Oil and Gas Projects?(a) IntroductionPNG has been applying the Additional Profit Tax (APT) since it was first introduced on Mining Projects namely OK Tedi and Pangua Mines. When oil development commenced in the early 1990s APT was applied on the first oil project – Kutubu in 1992 and other projects that were subsequently developed including Gobe and Moran. There were expectations that these projects would yield windfall revenues so that the Government could benefit from these revenues. However, to date, APT has not been triggered despite oil has been flowing for nearly 30 years. On account of the natural depletion of known oil reserves APT will not trigger on current oil project as the resource volumes have become marginal. It is not normal for APT to be paid on marginal projects and other APT trigger factors such as oil prices are low. These factors have also made the environment not conducive for APT to be paid on oil projects. Despite that, APT has been applied on the first gas development – the PNG LNG Project. APT has also been applied on Papua LNG Project and the same tax will be applied on P’nyang gas project. However, the experience tells us that APT did not trigger on oil projects. The essential question to ask then is; will APT trigger on gas projects? The economic projections of the gas projects indicate that these major world class gas projects will pay APT. However, over the course of production the assumptions based on which the projections were made change and so whether the gas projects will actually pay this windfall tax will depend on trigger factors. These factors are not limited to large resource volumes, high oil/gas price, low cost (capital cost and operating cost) and so forth. From the investment perspective, this tax is also capable of deterring investment. APT can scare the investors away if the government introduces this form of tax because investors would not be desirous to share the windfall revenues with the host Government. PNG had experienced the impact of removing APT in 2003. The exploration sector completely reversed when “incentive rates” which included removal of APT, as part of the fiscal package, was introduced in 2003. In 2002 only two APPLs (Application for Petroleum Prospecting Licenses) were received by the Department of Petroleum & Energy. However, as consequence of the new fiscal incentives the award of new PPLs increased to unprecedented height. This incentive, in particular, the removal of APT changed the landscape of the exploration sector in the country. To date, there has not been any proper investigation and assessment done to ascertain the real reasons behind APT not triggered or paid on oil projects? Despite that PNG Government is adamant to continue applying APT on petroleum developments, recently on gas projects. Have the successive Governments too weak to administer this complex tax? Is there any deliberate avoidance by oil companies to pay APT? While these questions need definite answers the factors that cause APT to trigger are both internal and external. For example, oil and gas prices are largely external to oil companies and governments. Oil companies have no influence over the prices. They are essentially price takers. However, some of the trigger factors such as cost may be controllable or manageable by companies. For example, if oil companies know when APT is likely to trigger they may increase cost ahead so that the point of APT trigger may be delayed or not paid at all. On the other hand, if the Government is determined to continue applying APT on hydrocarbon projects it must have the capacity to administer the tax collection. On the back of weak government administration especially, if tax office is weak important taxes may not be collected. It is a well-known fact that oil companies operate across borders, jurisdictions and different fiscal environments. They know the behaviours of the Governments and they can capitalise on the weakness of the government to their own advantage. If the Government is incapable of managing and administering complex taxes, they should consider simple, straight forward taxes which can be conveniently administered and collected rather than introducing a monster that also deter investments.This article discusses two aspects in relation to the Additional Profit Tax which is sometimes referred to Windfall Tax or Resource Rent Tax in some jurisdictions. First part deals with the background and general explanation of Additional Profit Tax as applied globally in hydrocarbon producing jurisdictions. The second part discusses the application of APT on oil and gas projects in Papua New Guinea; whether or not it is necessary to continue applying APT on all oil and gas projects in the country despite no APT has been collected from oil projects. (b) BackgroundTax is the main device by which the governments receive revenues from extraction of the resources it owns. Mineral and petroleum taxes are quite different from other taxes because of their special features. The oil, gas and mining projects are capital intensive, long lead-time; high cost of failure, high risk and finite life span hence, require special taxes. Beside the primary objective of raising revenues, the governments may be desirous to pursue social and economic policy objectives, promotion or destruction of industries or as a means of controlling sector development. Governments apply both direct and indirect taxes on mineral and petroleum projects. The governments may have genuine reasons for imposing taxes, but taxes can deter investments. One such tax is APT, which is charged at positive Net Present Value of the project cash flow. Resource producing countries apply this type of tax on resource projects. Papua New Guinea applies APT on oil and gas projects. Nevertheless, to date the Government has not collected this windfall tax from oil projects and is hoping that the gas projects will pay APT. There is no guarantee that APT will trigger on gas projects because the trigger of this tax is dependent on multiple factors. Does it make sense to continue introducing this tax or opt for simple taxes where the government can administer and collect tax? (c) Concept DefinitionTax is a payment an investor makes to the government for which it does not receive a return. While economists define tax that way, a layman’s definition is as powerful as it is. In this definition, tax is a payment investor makes to the government for the right to use its resource.The government, at different stages of project development applies various taxes; it could be well before the actual development of a project such as bonuses. Taxes may be broadly separated into direct and indirect taxes. Direct taxes are direct payments made by enterprises to governments, based on standing policies or laws in most jurisdictions. Direct taxes are collected by tax offices. Most common are Income Tax and examples of indirect taxes are import duty, export duty, stamp duty, sales tax, and excess taxes such as Resource Rent Tax.Indirect tax may extent to pre-development taxes like bonuses and license fees. Tax rates vary between fiscal regimes and point of payment also varies along the value chain of projects. Additional Profit Tax (APT) is an indirect tax applied by governments on resource projects and targeted at excess profits and can be quite complex administering it. In Norway, it is called Special Tax, in the UK it is called Petroleum Resource Tax (PRT), in Australia, it is termed Resource Rent Tax (RRT) and in the USA the tax is called Windfall Tax. PNG coupled with Ghana, Cameroon, Namibia and Gambia call it Additional Profit Tax. The threshold or uplift and tax rates vary between countries, but this tax targets a profit sharing scheme based on a rate of return. APT is calculated on a cash flow basis and payable when the accumulated value of net cash receipt is positive. It triggers after the project costs have been recovered and positive cash has been received hence; it should not deter investment. Such tax does not expect to distort production and investment because it has threshold that has been set to trigger additional taxation. However, APT has several weaknesses including difficulty in setting threshold rates, tax rates, and gold plating, which may scare investment.APPLICATION OF ADDITIONAL PROFIT TAX(d) Government ObjectivesThe primary aim of project host government is to ensure the economic benefits are derived from its resources development. The State is the legitimate authority, having sovereign power over its natural resources including petroleum from which it must share economic benefits with investors who put up investment, technology and essentially take huge risk especially at exploration stage. These benefits might be realised through the government’s fiscal measures designed to capture the maximum economic rent at an acceptable level of risks.The host government’s intention to benefit from the petroleum resources is enshrined in the country’s fiscal policy and legislative framework. Beside this, project agreements and license conditions may encompass similar conditions through which host government derive benefits from the natural resources. The primary fiscal devise employed in the extractive industry is taxation. It is to be noted that taxes are devices through which the government derives revenue from extraction of petroleum resources. Taxes applied on oil and gas projects are usually more than taxes imposed on other activities because of the high rents that are accrued from these resources. Tax may be also defined as price of exploiting public assets or resources. The government issues rights to companies to explore, develop, process and sale its resources, and in return the company pays government taxes. This is more common in royalty/tax or concessionary fiscal regimes.The government has multiple objectives for imposing tax on profits. This emanates from the government’s perception that it should share from any upsides or windfall profits investors make in the extraction of the natural resources. The governments raise money through taxation to maintain and develop the social, economic, infrastructure and other sectors in the country. The companies are targets of taxes because the governments need to raise as much as possible to address the country’s social welfare schemes. The government’s objective is also to demonstrate its ownership and control of the project. The governments know that they can maximise wealth from their natural resources through providing incentives and encouraging exploration and development of the resources. And this appears to be the driver instigating PNG to introduce APT on gas projects in the country in anticipation that this would allow the State to receive a reasonable share of profits from gas project in excess of a level which provides a good return to investors. The government considers adopting APT because of the advantages the windfall tax can generate such as the flexibility and non-deterrence on marginal profits. (e) APT Trigger PointTax and threshold rates vary between countries that apply APT on petroleum projects. In some countries, APT may be imposed on selected projects rather than all petroleum projects. There is a point in time APT is expected to trigger and this is directly related to net present value of the project. How this works is that; the investor is allowed specified threshold rate of return before tax can be paid to the government. The threshold rate of interest is used to compound forward investor’s cash flow until the accumulated total becomes positive. It is uncommon for the accumulated total to turn positive in the early years of production. APT triggers at the back end of the project cash flow when all the cash outlays attributable to the field and all the expenditures incurred are recovered. APT may become a nightmare from an administrative standpoint for government. APT permits threshold rate of return to be earned on the investment before the tax is payable. The scheme is designed to trigger automatically for profitable projects hence; trigger on marginal project is unpractical. It is highly sensitive to price fluctuations, exploration costs and marginality of the project. Clearly, these factors must also be considered when constructing APT. APT is a function of positive NPV, meaning it cannot trigger when the NPV is negative.CONCERNS REGARDING APT ON INVESTMENT(f) Concerns Regarding Designing APTThree issues emanate when designing APT which can distort investment in the petroleum industry. Firstly, it is a concern to investors when the Government enacts legislation that sets threshold rates that are below those employed by the companies. This follows from the fact that investors do not normally reveal their threshold rates that represent their discount rates to the Governments, as it is confidential and commercially sensitive. Especially, in Royalty/Tax systems, Governments don’t have access to critical and important information resulting in estimating discount rates way out of proportion. It becomes grave concern to investors when the government introduce rates that do not match companies’ estimates. The government’s threshold rates should not be greater than the average returns on comparable investments. The rate of return is a measure, which indicates to the companies their return on investment. A rate away from investors can be a source of grave worry to the investors and undermine investment prospects in the country.The second concern regards the higher APT rates imposed on the profits when other fiscal devices such as royalties, corporate tax, withholding tax, import duty, and GST have higher rates. Though APT triggers after the cost has been recovered the imposition of this tax becomes burden to the companies because this tax comes out of their cashflows. APT is an additional tax and so the companies view this tax as a concern if governments introduce it. Thirdly, Government’s selection of the expenditures, especially what constitutes the tax allowance is concern to the investors. The companies prefer a tax base that is wide, incorporating expenditures outside ring fence or outside the project in question. The narrower the tax base, the higher tax rates it is for investors. Though project-by-project basis remains a normal function for taxation, companies may desire government to include non-project expenditures as allowable for tax purposes. Investors become uncomfortable if government narrows the tax base by way of deducting exploration cost from the same well, which is being developed. Against high exploration costs, poor rate of discoveries and other factors, which investors must bear, a narrower tax base could prohibit further investment. (g) Inflation and Exchange Rate VariationsIt can become investment prohibitive if divergence on inflation and exchange rates has not been fully accounted for when designing APT. Inflationary expectations vary over time between what is known as ‘real’ and ‘money’ rates of return. When additional profit tax rates are designed inflation is purposely or not purposely bypassed by governments. The investors are overburdened with the difference in the real and money value that changes over time from the point when tax is first introduced. A mere ignorance to inflationary expectations can ruin investors’ expectations. Similarly, variations in exchange rates can lead to investment distortion. It raises serious doubt when the Government fixes tax rates because this important aspect is easily overlooked. This can distort investment motive if companies are ‘forced’ into a situation where all calculations are done in host country’s currencies. Given situations where investors intend to remit profits to home countries or engaged in transactions involving foreign currencies, they could lose a lot of value than they would in transactions involving hard currencies. The other concern relates to the tax investors’ home country charges as consequence of delays in trigger period. The additional profit tax takes several years before it triggers especially, in the middle or at the back-end of project cashflows. During the long period the governments may charge tax that become burden to investors. This happens if the investor is incorporated in the host country. (h) Administrative NightmareThe administration of APT can be excessive, lacks efficiency, simplicity and does not provide incentives to investors. This questions the government’s inability to administer APT. The government may be questioned why it introduced such tax in the first place, which it is incapable of administrating it. PNG has not collected any APT from the oil projects despite reviews with appropriate adjustments made to the tax rates and thresholds rates. The rapid changes in the fiscal regime were done because the Government saw oil companies making huge profits while its share from the project were not forth coming. This policy however, did not work because it lacked efficiency, simplicity and stability. APT is furthermore, criticised as complex and lacking flexibility. This demonstrates one thing that the host government may have defined objective in constructing a fiscal device but if it fails to take into account investors’ concerns; this can ruin investors’ confidence. Further, frequent changes in fiscal policy would frustrate investors as they will be required to keep adjusting every time when a change has been made to the fiscal devices. It also creates additional costs and tasks where host governments may be wasting time designing and changing fiscal devices that do not work in the end.(i) Impacts on Exploration ActivitiesInvestors know the value from exploration and they also know that the value may be positive before tax. However, if it turns out to be negative after tax this could seriously impair exploration activities. No investors would continue exploration and risk money in an environment characterised by negative rate of return. APT could produce disincentive effects at the exploration stage of petroleum exploration activity. Further exploration activities will be affected which could have consequential impacts on other petroleum activities. The fact remains. For without any form of exploration activity going on in the country the oil and gas industry is presumed dead. In 2002, the government of PNG introduced set of fiscal incentives known as “Incentive Rates” which included the removal of APT as an incentive to exploration sector. These incentives immediately had direct impact on the country’s exploration sector. The incentives reversed the dwindling exploration sector to what it is today.(j) Host Governments not a Risk-TakerThe investors view the government’s bid for a share of profit as an additional burden on their cashflows. This stems from the view that the government is not a risk taker and so why should they be asking for a share from the profit. The governments however, dispute this point that it should benefit from the extraction of its resources it owns in the country. From international companies’ perspective, an excessive profit tax can be discouraging if companies’ exploration risks are not recognised and rewarded. The Government is already a recipient of other taxes such as royalty and corporate tax, which are long term and increased as the production reaches peak levels. In other words, this form of tax is progressive. The investors see the government sharing profit as a non-risk-sharing partner. This can demean further investment if the government continues to introduce fiscal devices that permit it to only benefit than to share the risks involved in converting petroleum resources into a profitable venture. In some countries where governments acquire equity in the projects they also pay their share of the exploration cost through reimbursements. In this way, governments could be seen to be sharing certain level of exploration risks. PNG Government reimburses past cost or sunk cost equivalent to its share of the participation interests in a project. This payment is treated as a point of entry into the project by the State through which the State becomes a participant in the project through its National Oil Company. This is referred to as “back-in right”. This point can become a contentious issue. The argument is that; why does the State has to be made to back-in, into the resource project which it already owns as a legitimate owner of the resources? It makes no sense from the ownership perspective.HOW MIGHT RISKS ASSOCIATED WITH APT BE ADDRESSED?(k) Measurers to Address RisksOne must understand where the government is coming from, as host of the resources. The governments have strong case for wanting to share the benefits from its resource extraction. On the other hand, companies spent hard cash on finding the resources and developing it. Considering this, rather than underestimating the position of one against the other, both parties must work on the negotiated outcome which seems a reasonable solution to designing a fair fiscal device. The following measures suggest how this deterrence to investments might be mitigated.(l) Open-Ended Threshold RatesBecause governments are often uninformed of the companies’ ROR they can enact tax rates which may be detrimental to investors. When a fiscal device is legislated it becomes a law which companies have no rule over it but, obligated to comply with the terms that is stipulated in the legislation. Remedies to these anomalies may be through “open-ended threshold rates.” In this case, the government must leave the tax rates to be negotiated with companies at the time when a project is being contemplated for development rather than legislating it into a law. This will enable both parties to arrive at an agreeable rate, which reflect the rate of return for the investor. Few countries have demonstrated this by simply leaving the terms to be negotiated. Such terms could be negotiated and agreed between the parties in the Project Agreements or Gas Agreements for specific projects. The Oil and Gas Act (Sections 183, 184 & 185) allows such agreements to be negotiated between the State and the project developers at the time of developing oil and gas projects. (m) Determination of Tax Rate ApplicationThe determination of the tax rate for APT is an important factor that requires considerable thought. If a higher tax rate is imposed on profits there is no guarantee for APT to trigger. Therefore, it is important that when a tax rate on profit is introduced, it must consider other fiscal measures levied by the government. The companies may already be overtaxed through fiscal devices available to the Government. A higher tax rate may unnecessarily penalise companies resulting in low or negative return to the government. It is quite usual for companies to be making lose hence, governments need to have a wider and broader perspective of the entire fiscal measures it employs in the sector. There have been experiences where APT, although introduced through legislations, such taxes may not trigger. Therefore, there may be no reason for introducing APT in the first place. Factors such as low oil price, marginal field status, high cost and other factors prevent APT to trigger. While the government is the resource owner with exception of US where the ownership lies in the landowners, it is unrealistic to introduce high tax rates, which do not meet the companies’ expectations. Better outcome for all parties may result from a negotiated outcome, rather imposing on one party or the other.(n) Wider Tax AllowancesWhat is important to the investors is the tax base or allowances rather than tax rate. Few governments may be willing to concede widening the tax base, but it is an incentive that must be considered. Here, the government grants allowances to companies to deduct non-project expenditure. The companies are given the permission to take expenditures from other fields or essentially, outside the definition of ring fence. This could be done at the expense of the ring fence concept, as the expenditures allowed for deduction goes beyond the boundaries of the project in question. It is a form of relief to oil companies as it provides wide tax base for taxation purposes. Other considerations may come into play if a company has lived in the country for a long period of time, more allowances may be granted. If the success rate of discovery is poor and cost of exploration is escalating high, relief, in the way of wider tax base would encourage investment.In the UK, tax relief was granted to oil companies when the Petroleum Rent Tax was in force. Special tax relief by way of enlarging the tax base should be considered as such incentives can encourage further investment. This also can trigger government-investor relationship. Additional profit tax is normally taxed on a contract-by-contract basis, which would mean unsuccessful exploration cost of one project might not be set off against another.(o) Tax IncentivesInvestors’ concerns regarding APT stems from the fact that there are congenital taxes such as royalty, corporate tax, and VAT and import duties. The government need to reduce other fiscal measures to give the investors some leverage to the investors already imposed on the companies. This should provide relief from paying heavy taxes. Certain countries provide tax credit scheme where companies implement infrastructural projects for which they claim credits. Investors are also given incentives such as tax holidays, especially on pioneering projects. If provisions do not exist in host country’s tax laws, others means should be explored as means of providing incentives to oil companies. If the government has imposed multiple taxes including APT, it should provide incentives that generally aim at investment or re-investment, so it encourages investors to generate return on their investments. PNG applies Tax Credit schemes in which companies build infrastructure projects for which they claim tax credit. The National Football Stadium in Port Moresby is a fine example of the application of the tax credit scheme. This scheme ensures real infrastructure development is built rather than having the oil money dwarfed in the national budgets. (p) Shield against InflationInflation could be detrimental to investors, if not handled well. Sufficient protection needs to be employed to shield off any inflationary effects. One measure could be use of interest rates to protect investors. However, interest rates may not work well in an inflationary environment. In this situation, incorporating some form of direct inflation indexing. In adopting two-tier APT, PNG linked it to the Consumer Price Index (CPI) which is an inflation index appropriate to the currency used for tax accounting, the US dollars. Inflationary measures were considered as protection when APT was first introduced. For instance, a 25% rate tax would trigger on cumulative net cash flow with 15% plus inflation of prior losses. Inflationary measures are considered essential hence; they must be taken on board when APT is considered. (q) Consideration for Hybrid SchemeAnother measure that could be considered for offsetting drawbacks of APT is to combine APT with standard company tax. “A preferable alternative is to combine the resource rent tax and the corporate tax with a provision for conditions accelerated depreciation designed to provide tax relief only in the range of possible outcomes whose expected return are less than supply price of investment or whose expected payback period exceeds desired periods. Company profit tax may be deducted when assessing APT through right-off of capital expenditure. However, such a measure could deter profitability of projects. To reduce risks and stabilise fiscal measures some jurisdictions combine resource rent tax with the normal taxation. Papua New Guinea along with other countries such as Namibia has combined APT with normal taxation applied on resource projects.(r) A ‘Neutral’ Environment for Government and InvestorGovernments and companies are two distinct institutions with distinct functions and objectives. The former desires its resources developed so it can manage the country from the proceeds from the project while the latter invest to maximise profits. Companies have the capabilities in terms of expertise, technology and exposure to adequate financial resources which governments don’t normally have at their disposal. But both have a common theme; to have their objectives achieved; hence a balance must be strike between them. The Government must not introduce fiscal measures, which may scare investors away. Investors on the other hand must co-operate with host governments, in ensuring adequate returns will be realised. In extractive industry, investors may not survive without co-operating with resources owners and on the other hand, government cannot progress without investment. These are fundamental prerequisite for development. If a fiscal measure such as APT is to be introduced, it must entail a fair rate that suits both parties. One area in which the investor and government may agree to introduce a fair APT is both parties agreeing on the uplift and tax rates. Reasonable rates may trigger APT earlier than delayed or not paid at all. THE EXPERIENCE OF APPLYING ADDIOTNAL PROFIT TAX ON OIL AND GAS PROJECTS IN PAPUA NEW GUINEA(s) Additional Profit Tax Application in Papua New Guinea Papua New Guinea has APT as a revenue generating device applied on both oil and gas projects. However, APT has been marked by inconsistent policy changes and shifts in desperation to have the tax trigger since it was first introduced. Initially, the country had a single tier APT and it introduced a two tier APT, removed APT through policy change and reinstated APT. In undertaking these changes there have been different uplift and tax rates introduced and removed. However, despite these changes, to date, none of the country’s oil and gas projects have paid APT. The following account the different changes that have been made to APT largely, in an effort to ensure this tax pays.(t) Single Tier APT Rates Applied On Oil ProjectsThe Additional Profit Tax applied mainly on oil projects prior to 2000 Tax Review headed by Sir Nagora Bogan was a single tier. This APT provisioned in Division 10- Subdivision D, Division 10A – Subdivision F and Division 10B –Subdivision F of the Income Tax Act was in force until 2000. The Additional Profit Tax has different application rates. APT had varying rates under three different fiscal regimes including general petroleum fiscal regime, gas fiscal terms and frontier fiscal terms. The threshold rates applied in the three fiscal regimes also had varying rates.Additional Profit Tax applied in the general petroleum fiscal regime was 50%. That meant when the additional profit tax triggers oil companies would pay 50% of the windfall profit to the government. The benchmark or rather the threshold rate of return when APT was expected to trigger was set at 27%. These rates were applied by the PNG Government mainly on oil projects.The additional profit tax rate applied to the gas sector was different. Under the gas fiscal terms, the additional profit tax rate was set at 30%. The threshold rate of return when additional profit tax was expected to trigger was 20%.The tax rate and threshold rate were applied differently in the frontier fiscal regime. It had a special tax rate of 35% with a 20% threshold rate of return. The trigger rates for gas and frontiers terms had same rate of 20% but differed in tax rates. (u) Introduction of Two Tiers APTOn recommendation of the Tax Review in 2000 a Two Tier APT was introduced. This emanated from the concerns that the accumulation rate was too high at 20%, resulting in non-sharing of benefits from moderate profitable projects, and it was recommended that APT that actually trigger should be introduced. It was opted that APT should be made a more sensitively progressive tax by introducing an extra tier. It was envisaged that the incremental rates of tax in each tier could be significantly lower in order to reach an overall outcome. The two tier APT was to encourage more benefits to the State while leaving substantial upside with the investors. In other words, APT should be one that does not damage the project and deter investment.In undertaking this change, the first tier of APT was levied at a rate of 20% when the accumulated value of after Corporate Tax cash flows was positive at a 15% nominal interest rate. The second tier was levied at a reduced rate of 25% when the achieved internal rate of return after Corporate Tax and first tier APT exceeds a 20% nominal rate. It was recommended that APT on gas income would be assessed separately for each designated gas project. It was further envisaged that the introduction of the two tier APT at the proposed rates and thresholds would not deter investment. The first project that had two tier APT is Moran Oil Project (PDL5). PNG LNG project has two tier APT. The APT for tier 1 has 17.5% uplift and tax rate of 7.5% whereas tier two has 20% uplift and 10% tax rate. However, in negotiating the Papua LNG Gas Agreement in 2019 the Government conceded to a single APT tier. Both the uplift and rate have the same rate of 15%. The basis of agreeing to 15% uplift and 15% tax rate in the Second LNG is unclear. For a profitably project like the Papua LNG with the resources base of 10.3 tcf, APT tax rate should be higher than the 15% agreed to in the agreement, as more upside is anticipated in the project provided that other trigger factors are working as anticipated. The State may be in danger of losing more upside benefits from this significant LNG development. (v) Removal of APT as Fiscal Incentive RatesInstigated by the industry’s concern that the 2000 Tax Review weren’t improving the country’s fiscal regime, dwindling exploration activity, a paucity of new field discoveries, similarly dwindling oil production and declining government revenues from proceeds in late 2002 the government introduced new fiscal incentive rates to rejuvenate the petroleum exploration sector and production activities in PNG under special terms called “incentive rate petroleum operations”. These fiscal incentive rates were designed to provide a strong stimulus to oil and gas companies already established in PNG and attract potential investors to explore, develop and produce the country’s petroleum resources. The new rates cover changes to the two vital elements of PNG’s petroleum fiscal system. (i) Abolition of Additional Profits TaxThe fiscal incentives resulted in the abolition of APT on all new petroleum projects that were granted PPL in the period 1st January 2003 to 31st December 2007 and any new PDLs emanating from these PPLs granted on or before 31st December 2017. The APT was an incremental tax on the accumulated value of net project receipts that is: net income less deductions uplifted of a set accumulated rate each year. The normal provisions for APT at the time were for a 20% tax on any positive balance of net projects receipts after applying a 15% accumulation rate, and a further 25% tax on any positive balance after applying a 20% accumulation rate. As part of the incentive package, the two tiers APT applied on all petroleum operations were removed on new projects. APT had been seen as a real disincentive, where it was triggered at a relatively low rate of return for a project developer. This was considered disproportionate to the risks assumed by the project developer. (ii) Corporate Tax Reduced to 30% on Oil ProjectsThe corporate tax rate was reduced from 50% and 45% tax rates to 30% for petroleum activities and operations. The new rates were only applicable to petroleum projects arising from PPLs granted in the period 1st January 2003 to 31st December 2007 and PDLs emanating from these PPLs granted on or before 31st of 2017.The removal of the APT had direct impact on the country’s exploration sector. The exploration sector in the country improved drastically. The PPLs awarded and the exploration expenditures improved remarkably from 2003-2008. As demonstrated in the chart below the fiscal incentives had positive impact on the exploration sector. As a consequence of introducing these incentives by the National Executive Council on 6th December 2002, the PPL holders at the time surrendered their existing licenses and top filled in order to qualify for the incentive rates. The new PPL applicants automatically qualified for the incentives. However, this incentive was a policy change rather than a legislative change. The Government did not give any legal effect hence; the incentive had no legal meaning. The expectations of the oil companies to benefit from these incentives were shuttered. This remains a fiscal blunder on the part of the Government because the incentive practically turned the dwindling exploration sector in PNG into positive outlook. In 2002, only a few PPL applications were lodged with the Department of Petroleum and Energy. However, this trend drastically changed in 2003 and beyond. Oil companies invested heavily in the exploration sector knowing that they would qualify for the incentives but the Government did not honour its commitment. However, there was a catch to the fiscal incentive rates. The PPLs awarded under the Incentives Rates would qualify for the incentives provided that the PPLs led to positive discoveries of hydrocarbon and must be awarded Petroleum Development License (PDL) on or before 31st of December 2017. Some companies such as InterOil – former owner of the Elk/Antelope gas discovery had argued that their license would qualify for the Incentive Rates because they too surrendered PPL 238 and top filled to qualify for the incentives. The Government stood by the position that this was a policy decision. New companies, especially, small players applied for new exploration licensees believing they would benefit from the Incentive Rates. However, the window for any negotiation was shut when the Government reversed its policy decision on APT and re-introduced it on PNG LNG Project. (w) Has APT Triggered in in PNG?There is a point in production life of a project in which APT is expected to trigger and this is directly related to net present value of the project. How this works is that; the investor is allowed specified threshold rate of return before tax can be paid to the government. The threshold rate of interest is used to compound forward the companies’ cashflows until the accumulated total becomes positive. It is uncommon for the accumulated total to turn positive in the early years of production. APT triggers at the back end of the project cash flow when all the cash outlays attributable to the field and all the expenditures incurred in the area have been recovered. The scheme is designed to trigger automatically for profitable projects.The experience in PNG is that the Government has not collected APT from petroleum operations in the country. The Hides Gas Project, Kutubu Oil Project and the Gobe and Moran Oil Projects have not paid APT. Have the successive Governments fallen into the trap of administrative nightmare? It is one thing to introduce tax devices on projects and it is another thing to ensure taxes are administered and collected. It has also been noted that APT trigger is subjected to multiple triggers. APT is sensitive to price fluctuations, exploration costs and other sensitivities. PNG’s hope is that the three world class major gas projects including PNG LNG, Papua LNG and P’nyang pay APT. These are huge projects capable of paying windfall tax but in order for this tax to trigger the factors that ensure APT to trigger must be working favourably. The economic projections which have been made for the gas projects are based on certain assumptions. The assumptions will change during the production life of the gas projects and so nothing is certain whether APT will be paid. APT is a windfall tax which is structured to trigger at the back end of the project cashflows. The downside of this tax is that the cream of the project revenues have been extracted upfront by the time APT is expected to trigger. The oil/gas price dwindle and project cost escalates; these are indications that APT may not be paid. The following factors have contributed to non-trigger of the APT in PNG; The threshold rate of 27% for general petroleum fiscal regime is probably high making it impossible for APT to trigger.The threshold rate of return was originally set in a high inflation environment at the time.The high rate of Corporate Tax and other tax-induced additions to costs which would enter the additional profit tax account.All petroleum operations in PNG are high cost operations and essentially no drastic cost reduction which would have allowed APT to trigger.The oil fields did not experience significant incremental increases in reserves. The incremental increase in Kutubu was minimal and to a large extent inadequate to trigger APT. On average, oil price has been generally low so the APT trigger was unlikely in PNG’s oil projects. In order for APT to trigger the above factors must work in unionism. Increase in one trigger factor such as oil price may not necessary cause APT to trigger. If one or few of the factors were to instigate APT to trigger they must be exceptionally perform well. (x) Can APT Be Avoided?It is important to remember that any government’s attempt to introduce a tax would be viewed by the companies as regressive device. Inevitably, the companies would not want Government to discuss anything in relation to introducing taxes, particularly new tax. The companies aim is to maximise their profit margins. Like other form of taxes the imposition of APT is a “cost” to the company although it triggers after all the costs have been recovered. It is to be noted that the APT impacts on the companies’ cashflows. Companies are asked to pay additional cost on top of the normal taxes such as corporate tax they pay to the host governments. There are several ways APT could be delayed or avoided;Based on certain assumptions companies know when APT will trigger during the production phase of projects. Know the trigger points the companies may deliberately make adjustments to trigger factors such as cost. Companies may increase costs such as capital expenditure or operating costs purposely to postpone or prevent APT from trigger. In-depth project knowledge and accessibility to critical information put the companies ahead of Governments where they may conveniently manipulate trigger factors within their control.Companies may consider securing increases to other form of taxes from the government such as import duties, export levy. These are essentially cost to the companies and could delay or prevent APT from trigger. This is especially, when the companies know that they may pay huge amount in APT.Certain companies may use concepts such as “marginal field” without giving too much information to the host Governments as a cover up. The companies may deliberately down grade a project status from a profitable project to a marginal project. In a scenario where the project is in total control of the companies and little to no checks done by the host governments things can go wrong. Companies predict when APT will likely to trigger and so they can intentionally down grade a project to marginal project to avoid paying APT.Companies may indirectly encourage government to raise threshold level to a higher rate so that additional profit tax may never trigger over project life. This happens when companies predetermine that APT would trigger for a particular project at a given threshold. This calls for the need of the host government to evaluate and analyse the project economics, independent of the companies.Lack of detail information and data of projects by governments is quite crucial. Companies can make things work in their favour since they know more than the host governments. The responsibility lies in the host government to use its regulatory powers and authority to fully understand the project. The government must be advised when APT will trigger so that additional costs incurred by the companies are not misleading. The government must demand more information/data and monitor any cost increases so that it is not misled. Mitigation to this issue is through State Participation through the NOC. However, the NOC must be a step up meaning, it must have a major stake in the project where it can play influential role. On the basis of minority stake, it will be difficult to shape the decisions in the JV or in the operation of the projects.It is to be noted that the additional profit tax is not part of the original cash flow of the project. It falls out of it essentially, and can easily go unmonitored by governments. That is why it is imperative on the part of the host governments to monitor the performance of the project. The Oil and Gas allows the Government to monitor all costs incurred by the companies in the country but given the state it is in, the Department of Petroleum & Energy does not monitor the cost trend. There was an attempt to create cost monitoring mechanism in the department years ago, funded by the World Bank Technical Assistance Project, but the inability and incapability of the Department continues to allow the companies to operate almost at will, and to a larger extent cost trends not monitored by the regulator. (y) Does it make Economic Sense for PNG to continue to apply APT on Oil and Gas Projects?The fact remains. Oil projects have not paid APT and the oil reserves are depleting. The APT trigger time has lapsed on oil projects hence; PNG will not get APT paid. In negotiating gas agreements the Government has pushed for APT and ensured it is one of the important taxes applied on gas projects. On current projections, the companies can estimate when APT is likely to trigger. However, despite the current economic and financial projections of the project showing APT trigger, it is impossible to be convinced all projects will pay APT. This uncertainty is brought about by the fact that the trigger factors that enable APT to pay change over time and the assumptions based on which the projections were made also change during the course of production. Some of the factors that would enable APT to trigger such as inflationary effects, exchange rates, low (gas) price and reservoir complication are beyond the dictates of the oil companies. These are external factors that the companies will have zero to little control over them. In reality, there is no guarantee that the Government will be paid the windfall tax it aspires from the gas projects. The other point is that the Government may lack administrative capacity to manage and administer monitoring and collection of complex taxes. Since the first crude production began in 1992 to end of 2019 a total volume of 531 Million barrels of oil (Mbbl) have been produced from the oil fields in the country. The oil reserves are depleting due to natural decline in oil reserves. There are no more major oil reserves left to be produced in the future. The government will never be paid APT on oil projects. The following table shows oil production from 1992 to 2019. The above table shows that approximately 531 Million barrels of oil (Mbbl) has been produced from 1992 to 2019. An estimated value in access of US$20 billion has been generated from the country’s oil development and production. Reaching peak production of 45 Mbbl in 1993 the oil production has since declined to less than 10 Mbbl at present. APT payment is practically impossible on account of the very low volume of oil production.In terms of gas projects three major gas projects with large volume of gas have been developed or proposed for development. These projects with their estimated volumes are shown the table below.Combining the above resources PNG has confirmed gas in access of 20 tcf. PNG LNG and Papua LNG have APT agreed in the respective gas agreements. P’nyang will certainly have APT agreed as a fiscal device. It is to be noted that the application of the Additional Profit Tax is part of the fiscal package the government accord to oil companies for gas development. PNG LNG is now six years into the production phase. Papua LNG has not yet commenced construction and P’nyang is under negotiations. Having missed tax revenues in APT from oil projects the Government will not want to miss out windfall tax from the gas development. But there is a catch to this expectation. The trigger of the windfall tax is subject to all trigger factors performing well so that the Government could collect this form of rent.Where does this leave the Government? Does it make sense to apply a monster tax that the Government cannot collect tax revenues on the one hand and on another deter investment? The Government may simply opt for other form of taxes where it can easily manage and administer. Preferably, increase those taxes that are paid up front or earlier on in the cashflow projections. For example, increase royalty, development levy or production levy and do away with ridiculously complex tax which may not trigger in the end. As noted, APTs are expected to trigger at the back-end of the projects where at this stage of production the projects are on the declining trend. The trigger factors such as resource volume are depleting, the cost of maintaining the operation are expensive and other factors such as prices are weak there may not have the capability to trigger any windfall tax. The Government should opt for a simple tax that can be conveniently administered and rents collected. The government agreed to apply APT on PNG LNG Project. Given a high cost of US$19 billion for developing the project a 6.9 MTPA size project with approximately US$12/MMBTU was enough to convince the State that APT would trigger. Current, PNG LNG is producing more than 6.9 MTPA; cost of maintaining operation remains high and the gas price has been very low below US$2/MMBTU in 2020. This scenario does not project a prospect that would enable APT to trigger. Papua LNG Project may project a different scenario. The project has a high resource volume of 10.3 TCF, the project cost is expected to be lower than PNG LNG Project, may be two thirds of the cost of the first LNG Project. Assuming that gas price trades at US$10-12/MMBTU or better and other factors are working in favour the likelihood of APT to trigger is there. However, if these assumptions change this will almost paint a gloomy picture about APT from the Government’s perspective. APT hinges on all or majority of the trigger factors performing as projected. Many lessons can be learned from the experiences so far as PNG has had APT since first oil production in 1992. Among the many lessons to be learned a large resource volume project may not necessary pay APT as expected by the government. The other factors must also work in favour to trigger APT and the government may be able to collect rents. The oil companies may manipulate certain trigger factors to their advantage which may result in APT trigger delayed or not paid. Given this, it makes sense for the Government to consider other form of taxes which it can easily predict, administer and collect.

IN LINE WITH THE VISION TO “TAKE BACK PNG”Article by: Roger Kewa AvinagaRoger Kewa Avinaga is an accomplished corporate and government executive and Board Director having worked in oil, gas, mining and energy sectors for 20 plus years. He also worked for an international organisation – The World Bank Group. He has in-depth knowledge, understanding and experience of business/commercial environment, financing, project procurement and management, economic/financial modelling, fiscal and regulatory regimes acquired through dealing with oil/mining companies, investors, banks/lenders, multilateral institutions, governments and key stakeholders in exploring new business opportunities, creating partnership, joint ventures, farm-out, project approval process and initiation to of major resource projects. “Take Back PNG” - Petroleum Sector PerspectiveA little over a year ago when the current Government took office it announced the new Government’s vision to lead the country to prosperity through undertaking some fundamental changes including taking hard line policy and legislative changes to the country’s petroleum sector. The Prime Minister said that it didn’t matter if the measures his Government take cost his job as the Prime Minister of Papua New Guinea. The Government adopted the slogan of “take back PNG” and to make Papua New Guinea become the “richest black nation” in the world. This is the bold move the Government announced since Independence. While some took this slogan as a positive vision to rescue and move the country forward others were disturbed off their comfort zone. For the Government to announce and take such a bold stand on “take back PNG” one would assume that the country is in “foreign control”. The Government could see that something is not right with the manner in which the country and its country’s resources has been managed to date. The Prime Minister had seen issues plaguing the nation despite of the fact that the country has abundant resources including oil, gas, minerals, forestry, fisheries and cash crops. The Government firmly believed that these issues will be appropriately dealt with and the country “regained” through translating and implementing the Government’s vision to “take back PNG”.Current StructureTaking back PNG may be interpreted from different angles. From the petroleum sector standpoint this may be defined as a vision to empower the role of the State and Papua New Guineans to fully participate through increased ownership and control of the petroleum resources development in the country. To achieve this, there must be drastic and structured changes made to the policy and legislative settings, fiscal regimes, restructuring of systems and processes, technical and compliance, among others. The country must increase ownership of the resources by ensuring the policies, laws, fiscal regimes, systems and processes are designed for fair and equitable distribution of resource benefits to every Papua New Guinean. The Government expects transparency, accountability and honesty in handling project benefits and discourages unfairness, bullying, greed, and everything that is wrong. The Government has also been very clear since taking office that it has no issues with oil companies operating in the country because the country needs them to bring clean money, technology, ideas, experience, skills and knowledge the country needs to develop the resources. It is probably fair to state that the manner in which the country’s oil and gas resources have been exploited is influenced and dictated by the policy, legislative and fiscal regimes the country has adopted since Independence. These systems have been structured to favour the foreign companies, and not so much the resource host country. The salient features that qualify this view are;Ownership structure – favours the oil companies on account of 77.5% equity ownership foreign companies own and 22.5% equity owned by the State.State has a minority stake on the basis of the 22.5% equity in petroleum projects.The industry is essentially controlled by foreign companies whereas the Government’s role is restricted to regulatory, fiscal and landowner related issues matters.All oil and gas projects are operated by foreign oil companies. Project benefits mostly favour foreign companies on account of more concessions/exemptions (discounts) granted to them. For example, in negotiating the PNG LNG and Papua LNG Gas Agreements the State exempted foreign companies from paying import/export taxes, Dividend Withholding Taxes, Goods and Services Tax, Tax Credit Scheme, among others. National Content Plan – zero to very limited local participation in the construction phase such as PNG companies not taking part in engineering work. On record PNG participation during construction of the PNG LNG accounted for around 10-20%. Foreign companies dominated this area.The State has lost control of the petroleum resources. Foreign corporations have taken ownership and control of the country’s important hydrocarbon assets. PNG’s destiny and future is at stake. PNG inherited a system that favours foreign companies more than the State. This is why the Government has committed to making fundamental changes and tidying up of the loopholes. The key drivers relevant to the hydrocarbon sector that underpin the Government’s vision to “take back PNG” constitute the following:A) Elevated participation in the exploitation and development of the petroleum resources,B) Equitable distribution of benefits across all stakeholders,C) Maximize value of the petroleum resources for lasting benefits to PNG communities,C) Self-sufficiency in the downstream and energy supply space,E) Improve the balance of payment and reduction of debt,F) Promote sustainable economic growth,G) Increased revenue generation.Furthermore, the drivers include increased ownership and control over the country’s important resources and assets, creation of investment opportunities for PNG citizens and reduction in capital flight abroad, increasing spill over effect on sectors of the economy and improving the living standard across communities and societies in the country. These are key economic drivers that will support taking back PNG.The government has an important role of promoting the national interest through actively facilitating policy, legislation and regulations. Without government intervention, very little will be achieved and the vision to “take back PNG” will not be achieved. Therefore, it is imperative that the Government ensures policy and legislative settings, systems and process re-defined and restructured to ensure maximum value from the resources are generated. Petroleum is BiggerPetroleum is bigger than we think and is crucial not to have a narrow view of this resource. The government mustn’t allow foreign companies to continue to play dominant role in the development of the resources. The State must elevate its position through increasing ownership and control of the country’s resources. The Government must be in the driver’s seat. Notice the following salient features of petroleum;Petroleum dictates and influences the global geopolitics and equated with politics, authority and power, and has the ability to create friendship and enemy across borders and within jurisdictions,Petroleum has the capability to dictate and influence the global economy, international business environment and movement of global trade. Notice the fluctuation of oil prices, it can either boost the global economy up or downgrade economy to a lowest point.Petroleum can also influence a country’s economic growth. Notice too that the country’s economy plummets when oil price hits rock bottom. It takes years for oil producing country to recover and rebuild its economy. Petroleum is characterised by high capital intensive and long lead time and long life span. Investment in oil and gas is too risky but highly profitable and pays off healthy dividend over many years to come.Petroleum industry is highly complex and sophisticated, covering different segments along the entire value chain including upstream (exploration and development), midstream (processing and refining) and downstream (petrochemicals, retailing and marketing) and connects different players along the entire value chain including oil companies, service providers such as drilling services, catering services, security services, engineering services, financiers/lenders, multilaterals, National Government, lower level governments, NGOs, Landowners, producers, off takers, buyers, sellers, traders, lenders, and transport providers.The Governments’ important priorities are not necessary oil companies’ priorities. Oil companies are dictated by corporate interests, profit maximisation and influenced by global factors such as price fluctuation, change in technology, niche markets and political dynamics. On the other hand, project host governments’ priorities are dictated by the need for infrastructure, social services such as health and education and development aspirations. Essentially, the priorities of the Governments and the corporate entities do not match. The decisions that the petroleum host governments make, the policies and laws that they design and develop must consider and embrace the important features of petroleum. The Government mustn’t make decisions in isolation from these features. The petroleum industry also attracts different players along the value chain such as sellers, off takers, financiers, service providers, governments, multilateral, landowners, lower level governments, NOCs and NGOs which have myriad of interests in the extraction and development of the oil and gas resources. Petroleum Sectoral Issues that Require ImprovementSeveral frontline issues directly affect the petroleum industry in Papua New Guinea. These issues need tidying up and the Marape Government has taken the initiative to take lead and resolve these issues through implementing the Government’s vision of “take back PNG”. The issues that must be the Government’s priority include;(a) State’s Passive Role in Petroleum Project DevelopmentThe extent to which the petroleum agreements or contracts are structured and drafted for exploration, development, processing, transportation and selling of the hydrocarbon resources are influenced and dictated by the fiscal regime the country adopted at the Independence. PNG adopted Royalty/Tax System or Concessionary fiscal system where rights are issued through permits/licenses to oil companies to explore, develop, pipe, process and sell petroleum. The Government in then collects rents through royalties and taxes. However, in PNG the State has legal right to acquire up to a 22.5% interest in a petroleum project. The 77.5% interest is retained by the oil companies. The State becomes a minority stakeholder with the 22.5% interest compared to the 77.5% oil companies take. The State’s 20.5% equity interest is managed by the National Oil Company, (Kumul Petroleum Holdings) and the landowners’ 2% equity is managed by the Mineral Resources Development Company (MRDC). The NOC becomes a Joint Venture Partner in petroleum projects through accession to the JVOA (Joint Venture Operating Agreement) and other agreements but the NOC retains minority stake in the project. If a project is integrated like the PNG LNG Project, the interest split flows through from the upstream to the downstream on pro rata basis. The NOC has minority stake in a project hence, its chances of elevating to the role of an operator is quite clearly remote. The NOC is also not expected to hold a veto power or major voting power on project operational issues as it is limited by the minority stake in the project. So from ownership and control standpoint it is the foreign companies who are in the driver’s seat. On the basis of the 77.5% interests the foreign corporations hold in a project they take on the operatorship role, control the management of the projects, and they can easily become very power and influential. The State becomes a passive player in the exploitation of the hydrocarbon resources in the country. (b) Change of Fiscal RegimeThe manner in which contracts, agreements, laws, taxation terms and State participation structured by petroleum host countries is dependent on the types of fiscal regime a country may have. The main fiscal system practised by petroleum producing countries include: Royalty/Tax System, Production Sharing Contracts (PSC), Service Agreements/Contracts and Hybrid fiscal regimes. Concerns have been registered regarding the country’s fiscal regime that it turn to favour foreign investor more than the State. PNG’s Royalty/Tax system was inherited during British and Australia colonial administration. Numerous calls have also been made for PNG to switch to other fiscal systems such as the Production Sharing Contract (PSC) practised by Malaysia and Indonesia, or other fiscal systems that may benefit the State more than the Royalty/Taxation system. Switching from one fiscal system to another isn’t a mere policy and legislative changes. It is more complex. Changes to a fiscal system must be backed up with comprehensive review, assessment and comparative analysis of the fiscal regime against fiscal systems of countries within the region or of other jurisdictions. The assessment will show where PNG sits in relation to benefit distribution, and more importantly whether or not there is any logic PNG switching to another system. In the past the Government made several attempts to review the Royalty/Tax system against other fiscal systems but none of these initiatives have been progressed further. However, the Marape Government has firmed up its position on switching from Royalty/Tax system to Production Sharing Contract. The fear is that the Government may head straight into making policy and legislative changes which is not the right approach. There must be qualifications for any changes contemplated as this will involve a major shift and overhauling of a well-established systems. Studies will demonstrate whether or not the current fiscal system can be abolished for another favourable system. This will require mobilising fiscal experts such as Van de Meurs, Wood Mackenzie, Daniel Johnstone and others. These studies must serve as prerequisite to policy and legislative changes. The best thing the Government can do is undertake a comparative analysis of the fiscal regimes to determine whether PNG is doing well or not under the Royalty/Tax regime. In the absence of such studies PNG will not know if project benefits are in its favour. On practical note, PNG may already be, on average, receiving more benefits than foreign investors under the current Royalty/Tax system, and if so there may be only minor adjustments required to the current Royalty/Tax system rather than the wholesale changes in view of switch to other fiscal system that might not work for PNG. A comprehensive review and assessment of PNG’s fiscal regime against similar fiscal regimes is necessary before embarking on policy and legislative changes. It is very clear changing of fiscal system is on the priority list of the Government for implementation and this will be undertaken as part of the petroleum sector wide improvements. The Government re-affirmed its position to change the country’s fiscal system during the recent amendments to the Oil and Gas Act 1998.(c) Legislative ReformCentral to the petroleum sector wide changes the Government is contemplating it has set his target of improving the country’s petroleum laws. There is general concern that the country’s laws have uncharacteristic flaws. This is why the country is missing on important project benefits derived from resources extraction such as oil, gas and minerals. Due to legal flaws and the country is also missing opportunities. Certain provisions of the law favour foreign oil companies hence, these foreign corporations have taken nearly full ownership and control of the country’s petroleum resources. Such predicament exists as result of gaps we have in the policies and laws. For example, section 165 of the Oil and Gas Act 1998 provides that the State will only take up to 22.5% equity interest in a project. This limits the State from increasing its equity position. The Government is obviously not keen on seeing the plight of the country continue in this form. The Government has set its eye on undertaking some serious corrective measures that ensure the legal flaws are appropriately addressed. Several underlying reasons underpin the Government’s determination to amend the petroleum law. The Marape Government has stuck with its commitment to amend the Oil and Gas Act. In introducing the Bill on the Floor of Parliament the Government defended its actions to amend the oil and gas laws: (a) Certain parts of the law are in conflict with the national interest, (b) The country has been missing on the resource benefits, (c) Some parts of the law are out dated and do not reflect the current trend of the industry, (d) The country does not have ownership and control over its resources. The country’s important oil and gas resources are in foreign hands through transfer of rights State grants to the companies in the form of permits and licenses. The Government has set its goal to correct the flaws in law which the Government is determined to implement it in the national interest of the country. The petroleum resources sector is owned and controlled by foreign corporations. The petroleum industry encompassing different segments along the value chain including exploration and development, midstream (processing/refining) as well as downstream (marketing/retailing) are operated and controlled by the foreign companies. The petroleum resource owner – the State comprising the National Government, Provincial Governments, Local Level Governments, and project impacted landowners have not had meaningful participation in the resource development. The petroleum sector requires major restructuring of the systems and processes, policy, legislative, fiscal and taxation regimes. These changes will improve the State’s position in terms of ownership, control, decision making and increased participation in resource development. The seriousness of the Government in changing the law was demonstrated in the recent amendment to the Oil and Gas Act 1998. This is the first of the series of amendments to follow. The first amendment to the Oil and Gas Act 1998 centred on two sections as outlined below; Sections 54, 56 & 57 of the Act had allowed the applicant of a Petroleum Development License (PDL) to take the matter to the Arbitration in the event the Ministers refused to grant the license. This attracts international Arbitrators and foreign countries involvement. None of the PNG lawyers or judges will be involved in the Arbitration because the foreign judges or lawyers have no local trainings or know the cultural context of PNG. This exposes the State at high risk of involving billions of kina which the country may not afford it. The amendment to the three sections ensures that there is no longer risk to the State; andThe other set of changes relate to Sections 183, 184 & 185 which deal with Agreements. The order of the country’s legislations should be that the Act is superior to the Agreement. In other words, the Agreements are product of the Act and therefore subjected to the law. However, prior to the amendment, the Agreements have been operating as though they are above the law. This, in itself, causes conflicts. The Agreements should be merely contractual arrangements and not given same or supreme status over the Acts. The flaw in the law has now been rectified through the amendment. The Oil and Gas Act 1998 remains supreme to agreements executed under sections 183, 184 and 185 of the same Act. The recent amendments to the Oil and Gas Act 1998 and passing of the same by Parliament copped criticisms from different sectors of the industry. The PNG Chamber of Mines and Petroleum and others in the industry circle criticised the amendment due to lack of consultation especially, with the industry. The argument concerning the amendment to the petroleum law may be subject of discussion at another time but from the Government’s commitment standpoint, the Government has in fact achieved its commitment to change the law. (d) Negotiating Gas AgreementsHaving negotiated the first and second LNG Gas Agreements the next major gas development is P’nyang. Experience of the first and second LNG projects has been seen as lost opportunity and giving away concessions to filthy rich oil companies. The experience from the PNG LNG would have provided sufficient lessons in order to negotiate better terms in Papua LNG. That did not happen. The experience in negotiating Papua LNG Project Agreement did not improve from the first LNG Project. The expectation of negotiating better terms in Papua LNG failed.The negotiations of the first and second LNG Projects generated more dissatisfaction among the State parties especially, regarding the manner in which the gas agreements were negotiated. Immediately following the formation, the Government re-negotiated the Papua LNG Gas Agreement but only with slight improvement. The four points the State team negotiated include National Content Plan, Third Party Access, LNG Shipping and commitment by the oil companies to inject additional foreign currency into the country. The re-negotiated terms were contained in a letter which stated that the four points would be negotiated. It appears that this may not be the final negotiated position meaning that the parties may negotiate again. The thing about both gas agreements is that they have been negotiated, signed off and so they are essentially done deals. These agreements cannot be unwinded. The agreements are legally binding and the parties have been locked in to the agreed terms. The PNG LNG project is six years into production. These agreements were “poorly” negotiated on the part of the State. However, on positive note these experiences should enable the State to improve on negotiating P’nyang Gas Agreement and future gas agreements. Future agreements should be handled differently from the experiences of the first and second gas agreements if the State wishes to see a better outcome. The important question is how can the State improve on the next gas agreement negotiations? The Government has taken a positive step in addressing the legal flaws. In the recent amendment to the Oil and Gas Act the Government has amended sections 183, 184 and 185 which deals with the agreements. The issue State had prior to the amendment had been that the agreements were superior to the Act, when it supposed to be subjected to the law. The agreements became powerful and dictated the same law that provisioned its existence. The recent amendment now ensures that Oil and Gas Act sits above the agreement and that is the right order. On account of the previous gas agreements concerns have been raised regarding the representations by the negotiators whether or not they have genuinely represented the State as the agreed terms fell below the expectations of the State. It is not known if the outcome of the agreements exposes the weakness in the negotiation techniques, the negotiating team and whether or not there have been clear directions from the Government as to what it really wants out of the negotiations. Past agreements have been “hijacked” or “dictated” by a handful including advisors thereby subjecting the agreements to abuse of processes and systems and ending up with the agreements that fail to serve the interests of the State. The repeat of the same is not expected by the Government in negotiating the P’nyang Gas Agreement. P’nyang is the only single largest gas volume of 4.2 tcf yet to be negotiated. Other discovered gas fields have less than 1 tcf and as low as below 100 bcf. The negotiators of P’nyang gas must ensure superior terms are achieved. The Government has stepped up when it tabled superior terms for negotiating P’nyang gas agreement. This made the project participants led by ExxonMobil reject the terms proposed by the State. The project participants argued that they did not stand the chance of generating sufficient benefits from investment on the basis of the terms proposed by the State. The State was never going to back down having given away more concessions to the companies on two major LNG projects. The State has lived with the bitterness of missed opportunities and giving away unqualified concessions but on this occasion, it had to step up with superior terms. The negotiation on P’nyang Gas Agreement has been deferred due to the COVID-19 pandemic but will resume anytime. The State team should stand by its proposed terms and negotiate it through with the project participants. If the negotiators achieve a superior outcomes this will be a positive achievement for the country. Having the right negotiation team, negotiation skills and in-depth industry knowledge are some of the key drivers the negotiators should possess to negotiate superior terms. The State may further improve its position by delaying the negotiation on P’nyang gas development until the policy and legislative framework is tidied up. There are several outstanding matters the Government can sort out first including changes to the Oil and Gas Act and finalisation of the Gas Template Agreement. The recent legislative amendments are an encouraging start. While further changes are made to the law the Government should focus on getting the Template Gas Agreement approved as this will serve as a model gas agreement for negotiating future gas agreements rather than reinventing a new gas agreement for every project that has been proposed for development. Further work is also required in developing the gas policies. The Government approved in principle three gas policies but further work is required in finalising them. Completing the outstanding tasks will enable the State to consolidate and strengthen its position in negotiating future gas agreements and ultimately achieve better outcomes. The State looks vulnerable without the policy and legislative framework in place. The delay in P’nyang gas agreement negotiation may be a blessing in disguise for the State to regroup and consolidate its position for tough negotiation with the project participants. (e) Further Areas for ImprovementFor a developing country like PNG its prosperity rely on foreign investment. Changes to policy and legislations should also consider the important roles played by the foreign companies in developing the resources sector. The foreign companies have the knowledge, experience, financial and technical resources that PNG as a growing nation surely requires to develop its oil, gas, minerals and other resources in the country. Further sectoral changes are required on the following fronts: (i) Institutional Restoration and StrengtheningThe Department of Petroleum and Energy is duly legislated institution of the Government responsible for the country’s hydrocarbon and energy. The Department’s role is to encourage exploration and development of the country’s petroleum and energy resources for the benefit of the country. Nevertheless, the Department has not lived up to its expectations in discharging the policy, regulatory and legislative roles due to lack of leadership and government support, high staff attrition and loss of motivation. Over time the important institution has disintegrated and lost credibility, lack impetus, drive and focus to promote and regulate the industry. The Department has lost leadership and direction in providing technical advice to the Government especially, during negotiating agreements. The department needs to be strengthened to effectively and efficiently fulfil its role through undertaking the following actions:A) Improve manpower planning and management in the Department,B) Restore confidence and motivation in the staff,C) Provide daily administration of the Department including budget management,D) Provide leadership and direction for the Department to actively lead in formulating policies, legislation and regulation, E) Strengthen the technical leadership role of the Department,F) Improve license processing and administration,G) Positive impact on landowner and lower level government relations. (ii) Petroleum Sector ImprovementThe progression of this country depends on who is in control and how well the State manages its resources. Up to this point, the petroleum industry has virtually been controlled and dominated by external players. In spite of the industry been the source of infrastructure development, revenue generation, creation of employment opportunities and economic growth the exploitation of the petroleum has been dictated by external parties. Driven by their corporate objectives, profit maximisation, and external factors such as niche market or narrow window of opportunity oil companies set time lines and project schedules when projects get developed. When opportunities are presented to better leverage State’s position those entrusted to negotiate better outcomes end up conceding to foreign companies’ agenda and compromise the State’s position. The Government must undertake sector wide restructuring of the systems and processes, policies, laws, fiscal, licensing systems and compliance administration to the extent that the country is in control of its destiny to economic growth, prosperity and independence.The Marape Government has clearly set its bearing on improving the petroleum sector in the country. The petroleum industry is highly complex and sophisticated. The sector encompasses different segments from the upstream to midstream and to downstream. Along these value chains, different policies are required to be developed and ensure the gas resources are developed for the benefit of the country and the stakeholders. There is no secret that the State wants more benefits from its resource extraction. But it has also set its bearing on improving ownership, control and active participation in the development of the country’s hydrocarbon resources. Consider the entire segments of the petroleum industry. There is a general feeling that the country’s petroleum industry is essentially controlled by the foreign companies from exploration and development, the midstream including processing/refining, marketing and retailing as well as pipeline infrastructure. The petroleum resources owner, the State has been pushed to the periphery. The State ends up being a minority stakeholder with the 22.5% interest it has in petroleum projects. Compare that with the 77.5% interest owned by the foreign companies State’s ownership of the project is four times less than the foreign companies’. The State has no control, no operatorship status and no involvement in project decisions. The role of the State is restricted to regulatory, legislative and policy role and obviously cannot play commercial and technical role. For this reason, it has created a NOC to assume the commercial role but the State owned entity cannot become an influential player because it carries a minority stake in the project. Increased participation in the resources sectors require some restructuring and overhauling of the systems and processes, policy, legislations, fiscal and taxation changes in order that the State’s expectations are met. One way would be to empower its entities with clearly defined ownership structure and control so that the country will meaningfully participate in the resources development. The Government is also adamant of improving the State’s position on certain issues some of which include;National Content Plan –improved and greater participation in the construction phase such as PNG companies taking part in certain engineering work.Domestic Market Obligation – clear policy on DMO gas including increasing the DMO gas from the recently agreed 5% DMO in the Papua LNG Project to up to 15% DMO.Third Party Access – the TPA policies to allow future producers and buyers to access infrastructure with reasonable tariff arrangements. Other specific issues that require tidying up include increased State equity participation, sunk cost and financing through carry arrangement. These have been the impediments to State playing increased role. ConclusionIt is important to point out that the real issues impacting the petroleum sector has been identified and discussed. Institutional restoration and strengthening is required as well as policy, legislative and regulatory changes. Also, the technical role of the Department needs to be improved and it can do so on the basis of instilling leadership, direction, motivation and confidence to the Department. Further, serious issues plague the industry especially, from the State playing dominant role in the development of its important resources. At present, the State has no control on how the petroleum resources are exploited by the foreign companies. The State is restricted to regulatory and policy role but in case where it participates in oil and gas projects it is restricted to a minority stake. As noted, even in cases where the State’s NOC participates in petroleum projects the NOC holds minority stake and therefore cannot play a dominant role. This format of managing the country’s important non-renewable assets must change. The petroleum resources are owned by the State and it should rightly take control of its resources. That is why critical changes are needed in the way the nation’s oil and gas resources have been exploited and developed to date. The Government’s vision of taking back PNG makes sense.Through embarking critical and important changes to policy setting, legislative framework and fiscal regimes, the State’s position will be elevated to taking control of the resources, driving economic growth and development aspiration. Given the current circumstance, the country cannot aspire to develop as a nation. After 45 years of Independence foreigners have dominated and controlled the petroleum industry. The changes proposed by the Government must seek to elevate the role of the State in the decision making and participation, exploitation and development of the hydrocarbon resources. It is time to re-think and re-shape the country’s destiny and the Government must take control of the country’s destiny. Further, it has to be pointed out here that whilst the Government is driving ”take back PNG” it should also be mindful of the fact that a system is as good as its people. The composition of the Boards and appointment of management team on to SOEs and Government Departments must be merit based and people who put the people’s and the country’s interests above theirs. The Government can make changes to the policies, laws, fiscal systems and processes and structures but it will be the people who will drive these changes. Having the right minded people, zero greed driven and those that aspire to take back PNG must be appointed. As the country move forward, it will be important to develop the country’s petroleum resources in a way that ensures all citizens benefit from the resources development. Drastic changes will ensure PNG participates directly in the benefits emanating from development of the nation’s oil and gas resources. This can be meaningfully achieved, if the Government is focused on “take back PNG”. Article by: Roger Kewa Avinaga

By: Hayley Danielle "Opportunities don't just happen, you need to create them" - Mark StevenIntroducing you to the side hustle; A type of employment undertaken in addition to one's full-time job. Side hustles are often things a person is passionate about, rather than a typical day job worked in order to make ends meet and I have the pleasure of knowing three entrepreneurs who are doing just that.Meet the young professionals Jimmy Segodi a Graphic Designer at PNG Cancer Foundation, Dion Kombeng a Production Executive at Media Playground Agency and Mark Steven an Analyst at Bank of Papua New Guinea. These guys have been successfully side hustling for 3 years now after launching businesses in their free time.Towards the end of 2016 Jimmy, Dion and Mark along with some supportive friends put together the band wONEm Direction also known locally as wONEm-D. A cheeky play on the UK boyband One Direction, with wonem in Tok Pisin meaning 'which'.Using each of their skill sets, they created a full brand identity including professional imagery and logos, social media pages and fun video creation. A week before they were due to play at their first event, they sent out a media release announcing their arrival to the music scene and cleverly marketed themselves to be noticed. Within three months of launching they appeared on local TV, grew their social media following and hosted a regular morning spot on Rait FM radio to write and sing songs from random words that the listeners would give to them! Regular gigs were being booked through Facebook Messenger and the band also started to write their own music. Apart from being professionally marketed, the guys made it a priority to learn covers of songs that had just been released in order to stay current and on trend. "No other band at the time in POM was bringing this kind of style and vibe to the local music scene" Jimmy mentions. With more exposure and their confidence increasing they began to put their own spin on these songs and in turn this grew their fanbase.Today this 'side hustle' has become so much more...wONEm-D was actually just the catalyst of everything that followed. Dion launched Kalimat Studios and also released a debut single titled Tiare which featured Jay Lieasi and was recorded and released under CHM, this single alone has been viewed by over five hundred thousand people on YouTube. So in order to keep momentum Dion then decided to write and release the popular song Denim Jacket independently.Following the success of these two singles Dion met Solomon Island Producer/Artist Chris Young to work on a song tilted Ride My Lane which has been Dion's most successful song to date, holding a number spot one on Apple Music in Fiji for over two months, plus it went to number one in PNG and Solomon Islands. Dion then teamed up with producer BDMNKA and worked on Dion's most recent track Heartache, featuring Jimmy Segodi. "We do the full video creation and photography for the singles and the guys assist with shoot day, artistic production and backing vocals" Says Dion, who is currently on tour in Australia supporting Pacific Reggae sensation Jahboy.Jimmy also manages his own Graphic Design company Mwasiana, something that is an absolute commodity in POM. His talents are recognised all over the city and he can often be inundated with requests for work, in addition to this he is the President of the Milne Bay Association. Jimmy when do you find time to sleep? "I love what I do and I know my purpose, once you can identify that, work does not feel like work it's a passion"Mark supports both bandmates with their businesses and takes on the role of manager when needed. He was able to secure the guys a gig every Friday for the 'Members Night' at the prestigious Oil Search Football Stadium and also some Sunday sessions at the fabulous restaurant Mojo Social."We have travelled to play at two weddings in the last year, one being in Kokopo, East New Britain Province and the other in Townsville, Australia. We have also covered Tabubil town, located in the Star Mountains area of the North Fly District of Western Province for a member’s event. It's been a busy but fun time" Mark said.The big question is, do you consider yourselves entrepreneurs?"I guess so" says Mark."Apart from being musicians and performers, the team has taken on other activities like event planning, turning into fully fledged Cinematographers and content creators""I never realised it until you brought it up" Jimmy says. "But yes, I feel as a band we are young entrepreneurs. We manage not just wONEm-D but we also manage our collaborations with other established local talents such as David Vaname of Insomnia, Leeroy Chung and other upcoming artists." 'We have our day jobs and individually we have our own small businesses. Like Jimmy has Mwasiana where he does graphic work and Mark does his bits of management here and there and I do multimedia stuff as a small business. Our aim and hope for wONEm Direction is not only to grow as a band but also to encourage and expose other talented musicians we know or come across." Dion concludes. Jimmy, Mark and Dion are fresh, talented and driven. They are the new generation of Papua New Guineans who are ready to take on more than just one opportunity to make a positive impact. They inspire and talk to their audience through their consistent and engaging use of social media and they also understand the key fundamentals of brand and marketing in order to be successful side hustlers. Watch this space, as I am sure we are going to be hearing a lot more in the future from these three young entrepreneurs.

A Papua New Guinean is one of only nine (09) finalists in a global drone competition after his innovative idea was chosen from among nearly 1,000 worldwide entries.When WeRobotics launched the Unusual Solutions Competition back in June 2019, they wanted to find innovators using drones and data to address their communities’ most pressing challenges. Participants did not have to be experts in drone technology or own a drone. But, they were required to be innovative in the use of drones and data and have an in-depth understanding of the communities they were proposing to help.All finalists received a US $15,000 grant to turn their idea into a concept during the next four (04) months and prepare for the ‘Final Pitch’ event, to be held in early February in Panama City. At the pitch event, the best overall solution will win US $100,000, proudly sponsored, like the rest of the challenge, by the Omidyar Network. McLaren Hoping, a young Papua New Guinean male who completed a Bachelor’s Degree in Geographic Information Science (GIS) under the Surveying & Land Studies department at the University of Technology in Lae in 2018, found out about the competition from school colleagues. After visiting the WeRobotics website and reviewing the three challenges, he felt confident in participating in the Last Data Mile challenge.He was supported in his endeavour by Butibam Progress Incorporated – real estate firm of the Butibam people, the Hoping’s and Ahi’s of Butibam village, Lae and the Yaru’s in Sydney.“Having submitted an idea that has been accepted and supported by experts from an international organization is an indication that any small innovation can have the potential to move mountains and make a real difference in the community. “The only thing that matters is presenting it to the right people and at the right time,” McLaren said.“This opportunity will allow me to turn an idea into a fully-fledged solution within four (04) months. It will become a prototype to be implemented in the Ward 2 of Ahi Rural LLG. With adequate support and funding, we could do the same for other wards in the LLG, other rural LLGs in the province, and other provinces in the country, in the future,” he added. Ideas were required to address one of three challenges that included Drone Data & AI Tools, Last Data Mile and Drone & Data Ethics. His winning idea is to map households, using drone imagery technology and GIS to describe the conditions of sanitation facilities with the aim of raising awareness on the issue of poor sanitation facilities in communities, in the hope that the Government will put more attention to address the issue, which had been neglected over many years. WeRobotics was formed in December 2015 as a not-for-profit organisation dedicated to bringing developing countries access to robotics technology, and then to deploy it for social good projects within their communities. WeRobotics co-creates and facilitates a network of local knowledge hubs in Africa, Asia and Latin America to build on existing expertise in drones, data and AI, known as Flying Labs. PNG Flying Labs was launched in February, 2019 in Port Moresby during the first cargo drone workshop for medical delivery.The PNG Flying Labs is headed by local Coordinators, Sophia-Joy Soli and husband, Dr Kevin Soli, both of whom have remote flying licenses attained from US and Australia respectively. PNG Flying Labs recently held PNG’s first ever Drones Safety Workshop in conjunction with the IBS University at 11 Mile, Central Province. This was officially opened by Deputy Prime Minister Davis Steven. During his Keynote remarks DPM Davis encouraged PNG Flying Labs to organise more workshops aimed at schools to build local capacity and promote STEM. The workshop report can be downloaded here [http://bit.do/1st-png-drone-safety-workshop]“We believe in local capacity building and to channel the opportunity to local communities where they can have access to technology and to leverage the skills that come with the technology to make a meaningful difference,” the Soli couple highlighted. They are proud of McLaren’s local initiative and looking forward to assisting him accomplishing his project deliverables.McLaren strongly recommends drones for social challenges, particularly in geographically challenging PNG because ‘they are efficient when required to get the job done’.He aims to be innovative in promoting the use of drones, Geographic Information Systems (GIS) and its capabilities in addressing the many social issues affecting our local communities and to develop platforms that would facilitate their planning and decision making for a better living.

This is a story about a complex workplace issue - drug resistant TB and the time it takes to make a difference to change health behaviours. Most importantly it is a story about, Vidi, a TB patient and Brian Bell employee and Joan a TB warden at Brian Bell. Vidi is a 28-year-old man from Central and New Ireland who has worked with Brian Bell since 2016. Joan has worked for 17 years with Brian Bell and is from Kagua in Southern Highlands Province. Together they have a success stoy to tell about the role of the workplace in ending TB in PNG.In 2018 Vidi suddenly lost a lot of weight and was having night sweats. At the time Vidi didn’t think he was sick, but as he lost more and more weight, he decided to look for help. He went to several private clinics, but not one offered a solution to his sudden loss of health. On his fourth try for help, he went to the 6-mile clinic, where, because he had signs of extra-pulmonary TB he was referred to Port Moresby General Hospital. At PoM Gen, he was started on a regime of 6 months of TB treatment. Brian Bell gave him leave for 6 months.For a while, it was going well, but Vidi returned to the hospital when a lymph node on his neck started to swell 3 months into his 6-month treatment regime. Using the latest diagnostic tool called the “Genexpert” a sample taken from Vidi’s swollen lymph glands revealed he had drug-resistant extra-pulmonary TB. Meanwhile, back at work Joan Kundiri, Vidi’s line manager at Brian Bell, had attended Businesses for Health’s TB Warden training. Joan re-considered her colleague Vidi’s situation. She had learned to ask about Vidi’s diagnosis and case management. She considered, “had Vidi been tested with Genexpert at first test, why did he have to be away from work, and why was he not responding to treatment?”At TB wardens’ training Joan, learned extra pulmonary TB is not infectious. She considered Vidi’s situation and wondered if Vidi may be able to return to work without fear of him spreading it to others in the workplace. Indeed, Joan followed up with Vidi and he was deemed the doctors to be non-infectious and that Vidi had now been diagnosed using the latest in accurate diagnosis of DR or drug resistant TB. Joan is one of the first TB wardens to know PNG is working to replace microscopy with the rapid molecular GeneXpert test as the initial diagnostic tool for TB. This ensures that every patient at the time of diagnosis knows their drug resistance TB status and accordingly gets the correct treatment regimen from day one!Joan had to create a change in the knowledge and processes at work that would allow Vidi to return to his job. Whilst medically safe to return to work, Joan had to help HR understand the new methods for helping employees with TB about safe return to work. Several meetings at work lots of conversation with Nerrie and Catherine in the B4H office and even more encouragement for Vidi, Joan paved the way with Brian Bell’s HR for Vidi to return to work. After DRTB diagnosis, Vidi’s TB was still “extra-pulmonary”, but now his 6-month of treatment course was extended to 20 months, more TB drugs and for the first six months daily injections of the ‘second line’ DRTB drugs. Despite his major setback to getting better Vidi kept a positive attitude, but he was uncertain if he would be allowed to return to work, or be ordered to stay away from work for the whole duration of his new 20-month treatment regime. Re-enter Joan – Brian Bell TB warden! Three months later, Joan had Vidi back to work. With her now trained mind and new knowledge of TB Joan made sure that Vidi, who was still on medication and daily injectables, was in a supportive workplace environment. Joan met with HR and her management teams. She hosted toolbox sessions with her staff, B4H and ensured they understood TB better. Her work reduced the stigma around TB amongst her staff and created a better environment for supporting treatment completion. Joan made sure that Vidi had transport to go to 6-mile clinic to have his daily injections of the special drugs for drug resistant TB. Joan checked on Vidi daily and to see if he was showing improvement.Vidi’s recovery was remarkable, still taking medication Vidi was able to return to work with the support of Joan and the team at Brian Bell. At Businesses for Health, as far as we know, Brian Bell is be the first business to return a person with DR TB to work whist on treatment. It is a vital step in reducing fear and stigma that still surrounds TB at work. Vidi still has a job and Brian Bell still has Vidi. Vidi remains at work having endured the worst of the DR treatment regimens and will continue his tablets into 2020. Although Joan admits that they are still improvements to be made in the policy surrounding TB at her workplace she also knows that fear, stigma and knowledge of TB management are complex issues that take time to change. Importantly her colleague is on the path to full recovery and Vidi continues to support his family while on treatment. For Joan the more she contributes to helping people like Vidi get diagnosed, the better it is for her employer.In PNG in 2018, there were 37,000 new cases of TB. Five percent of those new cases were found to be drug resistant (DR). In people previously treated for TB, the rate of drug resistance is 25%.

By Independent Power Producers of Papua New Guinea Industry GroupPower generation and transmission in small island developing states (SIDS) is typically more expensive and challenging than in larger economies. That is a reality faced by Papua New Guinea (PNG), yet often misunderstood or ignored. There are many challenges that island nations face in powering their economies with affordable, reliable, sustainable and accessible electricity. The issues that faces both the Independent Power Producers (IPPs) and the Utility revolves mostly around several key areas, including cost, scale, demand and reliability – as well as an increasing push for renewable energy. For SIDS like PNG the pathway to develop reliable and affordable, and ultimately cheap, power is not forged overnight, it requires a collective effort by the Utility, the regulator, Government and Independent Power Producers to overcome systemic challenges and misconceptions. Diversified Portfolio Grid-based electricity supply rarely has one single generation solution. There are different types of power generation options needed by a grid, each with dispatch at very different levels. Baseload power runs all the time, so this type needs to have a low total cost. The cost of power to the Utility is usually agreed in a Power Purchase Agreement (PPA), which is typically structured in two parts: a capacity charge (fixed costs) paid by the Utility for the whole capacity contracted; and the dispatch cost (fuel charge), which is paid if and when the generator dispatches power to the grid. Baseload power therefore generally requires a low combination of capacity charge and dispatch cost, but it also needs to fit the size of the baseload demand to minimise unused capacity charges which the Utility would still pay for in the capacity charge – making the overall cost higher.Additional daytime power demand is usually high and varies throughout the day, so midday generation needs to be able to follow the load requirement of the ‘shoulder’ during the day when energy demand increases and then decreases. Commonly there is also a short peak demand window in which generation needs to be able to quickly respond. The type of generation required during daytime variations needs to be sized for the variable and largely predictable daily demand shoulder and peak. The best solution is usually determined by network forecast modelling with different supply options (technology type, PPA cost and size) in order to find the optimal cost and capacity solution. Reliable grids also require an appropriate level of fast response dispatchable sources as a backup supply. With backup supply mostly on stand-by and only used for a small amount of the time, the backup generation needs to be the lowest possible capacity charge, while it can stand a high(er) dispatch charge – and for a reliable grid may rarely be dispatched. As an example of such a diversified and distributed mix of generation is shown for an estimated weekday demand curve of PNG’s Ramu Grid in 2024 (see Figure 2). Having in place the correct distributed generation mix plays an important role in ensuring that power supply is reliable, secured and resilient to climatic changes. It also provides the Utility with various low cost and flexible generators that that easily be dispatched on their economic merits. Cost Versus Scale Versus Demand The cost of power is related to economies of scale. If the grid is large enough, it can deploy large projects to achieve these economies of scale. The larger the scale of the energy project, the cheaper the cost per megawatt (MW). However, and this is where there is often a misconception, a cheap cost per MW for a large project requires the scale of the power generation (how many MW) to be matched to grid demand. Oversizing a power plant to a large scale (e.g., a large 200 MW generation source) while demand is much lower (e.g., 90 MW) will not result in cheap power, as capacity charges are paid by customers for 200 MW, whether it is used or not. The Utility will still be paying for capacity which is not being used (i.e., a high capacity charge) which effectively drives up the average cost of the energy dispatched and results in a high power price. The size of contracted generation capacity therefore needs to anticipate and match grid demand. There is often a temptation to believe that demand will drive up scale and scale will drive down cost. However, a realistic pace of household connection rollouts in PNG indicates that a need for another 100 MW of baseload supply will take a decade or longer. In the case of PNG, only an estimated 13% of the population has access to electricity and there is future latent demand, but only a small amount of current household demand as increased access will require a long-term connection program. The power requirements for a million people connected in rural areas is only around 30-50 MW as the use of LED lighting, improvements in appliance efficiency, and a number of other factors, mean that household demand is not a large number and growth occurs relatively slowly. A critical element in stimulating grid demand for commercial and business customers, who comprise the majority of demand on the Ramu Grid, is enhancing grid reliability through upgrading transmission and distribution infrastructure. In other words, generation is only one part of the power equation – adding more megawatts of generation than currently required rarely solves the cost-scale-demand issue. Smaller grids can more cost effectively grow by deploying modular additions of 15 - 40 MW of power, which encourage new customers without burdening the system with the cost of too many unused MW. Representative Benchmarks Another problem frequently causing confusion over the realistic cost of power generation in SIDS is the incorrect comparison made with power prices in large economies that have already achieved significant grid scale and cheaper electricity. With no representative fleet of power station construction in the Pacific Islands region, many studies on “least cost power development” for PNG quote Asian construction cost and power cost figures as surrogate benchmarks. However, these are not appropriate cost analogues and do not reflect the true cost of generation in small island economies where there is no established low-cost power plant construction or servicing capability, and power plant scale is smaller. This problem is not unique to PNG, it is a shared challenge across the Pacific and Caribbean SIDS (Figure 3). It is unrealistic given PNG’s current level of construction capability, grid supply levels and demand for electricity (currently around 90 MW on the Ramu Grid) to achieve power prices like Thailand and Indonesia where grid demand and reliability is so much greater (over 40,000 MW in Thailand) – which enables those countries to have large energy projects that deliver cheap unit-cost electricity. Benchmarking PNG’s power price on large Asian economies creates unrealistic expectations of the cost of power generation. Demanding the low power price points of large economies overseas is not helpful in making power prices in SIDS more affordable – rather it will have the opposite effect and can deter potential investors who know that construction and operation costs in PNG are not the same as in OECD or large Asian economies. Price expectations based on countries with a very different cost and market compared to SIDS often create unnecessary delays to existing project developers (driving costs further up). These unrealistic price expectations help to condemn island economies to default to what has long been their cheapest capital cost generation – in most cases heavy fuel oil and/or diesel. These types of generation are the highest cost options for consumers (when fuel is included) until infrastructure becomes more reliable and grid demand grows – unless renewables can be deployed at a lower cost. The ongoing public debate in PNG centres around the cost of generation, leading to the misconception that the cost of generation is the primary influence in the overall cost of power. However, generally the cost of generation, transmission and distribution are approximately one-third each of the total cost of power. While the cost of generation needs to be as low as reasonably possibly, there are other significant costs which contribute to the overall cost of power that need to be taken into consideration. Incremental Growth To achieve lower power prices, SIDS need to invest incrementally in electricity infrastructure development that builds the country’s industrial base to grow future demand which in turn opens pathways for energy solutions that are larger scale and lower cost. The reality is that PNG’s power sector cannot evolve overnight to immediately deliver the cheap cost for construction and provide the price point of large-scale overseas economies. Right now, the country needs smaller projects matched to grid demand for incremental and distributed growth. These small incremental and distributed generation projects (up to 40 MW) are not going to be as cheap as the large-scale projects in Asia. However, that does not mean they will be expensive, renewable options at the 15-40 MW scale can be deployed at a low cost. Smaller scale distributed projects can provide a significant improvement in price below heavy fuel oil or diesel and do not burden the State with payments for large amounts of unused MW. While demand grows gradually, these smaller projects will deliver affordable energy and put the country on the right path to future larger scale demand and ultimately the cheap solutions we now dream about.