Ongoing energy projects to boost growth in Papua New Guinea


Much of Papua New Guinea’s economic success over the past decade, along with its prospects for future growth going forward, can be tied directly to the energy sector. The efficient construction and operational launch of the country’s first liquefied natural gas (LNG) programme – the ExxonMobil-driven PNG LNG project – not only secured unprecedented foreign direct investment (FDI) into the country and provided a stable revenue stream for years to come, but also delivered evidence that large, capital-intensive projects could be delivered effectively.

With this proof of concept now established though the partnership of large international oil companies and the government of PNG, the door is open for further large-scale hydrocarbons recovery projects across the country. The relatively low development costs of these capital-intensive projects also bodes well for the future of the industry. In the long term, exploration activities, while somewhat scaled back, look set to continue as companies search to unlock the next major hydrocarbons deposit within PNG’s vast and still largely untapped potential. “Exploration activities certainly slowed down in PNG as a reflection of low oil prices on the international markets, but that has affected mainly wild cat sort of companies, while majors or supermajors have continued with their commitment wells,” Wapu Sonk, managing director of Kumul Petroleum, told OBG. “Smaller companies are farming out at the moment and I would not be surprised to see a number of mergers and acquisitions taking place vis-à-vis the future.”

In terms of electricity generation, much also depends on bulking up the underdeveloped industry from new power generation capacity and bolstering the transmission capabilities to extending distribution to greater numbers of the populace. To this end, public and private sector interests have made strides in recent years to add much-needed generation to the major grids, while state power operator PNG Power Limited (PPL), with the help of international donor agencies, is moving forward with its rural electrification plans.

Revenue Stream 

Still the most prominent undertaking in the country, the PNG LNG project remains the engine of not only the energy sector but of the larger national economy as well. In its first full year of operations, the mega-project performed as advertised in 2015 and shipped out more than 100 cargo shipments.

Natural gas production nearly doubled from 57.87bn standard cu feet (scf) in 2014 to 103.84bn scf in 2015. The bulk of this was piped from the PNG LNG project, representing 96,65bn scf of output, leaving 5.31bn scf for the Hides gas-to-electricity (GTE) project and 1.89bn scf for the SE Gobe gas project. To accommodate this substantial increase in output, the project as a whole operated consistently above its nameplate capacity of 6.9m tonnes per annum (tpa), averaging 7.4m tpa in 2015 with facility processing performance improving progressively over the course of the year.


The natural gas is sourced from the Western and Hela Provinces from the Hides, Angore and Juha gas fields, with additional supplies derived from associated gas resources in the operating oil fields of Kutubu, Agogo, Gobe and Moran. Field development continued in 2015 with drilling focused on the Angore field, including the successful A1 and A2 wells, which intersected the Toro reservoir, along with the F1 well in the Hides field, which likewise intersected the same reservoir. Once processed at the Hides plant, the natural gas transits through a 32-inch-diameter pipeline snaking more than 700 km (300 km onshore and 415 km undersea) and dropping nearly 1000 metres in elevation through the mountains to the coastal facilities at Kopi, located just outside Port Moresby. This 700-ha site houses the two-train LNG plant, two 160,000-cu-metre storage tanks and associated support facilities. From here the gas moves through an undersea pipeline out to an export platform managed by Esso Highlands Limited (EHL), a subsidiary of ExxonMobil, for loading onto LNG tankers ranging in capacity from 125,000 to 220,000 cu metres. Depending upon the exploratory results of additional nearby tenements, as well as the ultimate composition of a likely greenfield operation running parallel to PNG LNG, there remains a possibility of adding a third LNG train to the project going forward, although likely not until the end of the decade. The development of the third train would look different from the initial project, however, due to the need to obtain new licences for the area, with the government likely to include a larger domestic share of the gas as a condition of the contract.

Project operator ExxonMobil is also PNG LNG’s largest stakeholder, with a 33.2% share in the project through EHL. Other project participants include Oil Search, with a 29% interest, Kumul Petroleum with 16.6%, Australian energy company Santos with 13.5%, Japan’s JX Nippon Oil and Gas Exploration with 4.7%, PNG landowner group Mineral Resources Development Company with 2.8% and state-owned Petromin PNG Holdings with 0.2%. A series of cost overruns caused by a wide range of issues – such as currency depreciation, poor weather and landowner disputes – have pushed investment costs from the original estimates of $15.7bn to around $19bn.

Contracts & Customers

In spite of the global economic downturn, Asia’s continued appetite for energy remains strong and PNG is well placed to supply the region in the coming years. This is apparent in the geographic makeup of the four long-term contracts signed for PNG LNG, which include the Taiwan-based Chinese Petroleum Corporation with an order of 1.2m tpa of LNG, Osaka Gas with 1.5m tpa, Tokyo Electric Power Company with 1.8m tpa and Unipec Asia Company, a subsidiary of China’s Sinopec, with 2m tpa.

Even with the unfavourable global energy prices pushing down revenues, mineral exports – including LNG and condensates – still reached PGK19.43bn ($6.6bn) for 2015, outpacing the total of PGK17.72bn ($6bn) exported in 2014. Moreover, these exports accounted for almost 84% of total merchandise exports in 2015. Of the 101 LNG cargoes shipped from the country, 80 were sold according to the four long-term sales contracts, while 14 of the remaining 22 uncontracted gas cargoes sold on the spot market went to the same four buyers. In addition to natural gas, 31.5 equivalent cargoes of “Kutubu Blend”, which is comprised of production from the Oil Search-operated PNG oil fields and condensate from the PNG LNG project, along with eight cargoes of naphtha from the project, were also sold in 2015.

Up And Coming

Just to the south-east of the highlands gas fields lies what is widely expected to be the next big LNG project, Papua LNG, led by majority stakeholder and French energy giant Total (see analysis). Extensive exploratory work is already under way, with a final investment decision (FID) expected by 2018. This date represents a critical crossroads, as the country will find out if the next big investment wave will be initialised or if the project partners decide the project is unviable and cut their losses. If the decision is the former, 2018 could be the beginning of a new wave of FDI stimulating the domestic market, coming initially in the form of engineering and procurement contracts that could be launched in the same year.

In addition to the encouraging results from the ongoing exploratory work, the project has a number of benefits that appear to tilt the FID in favour of approval. The proximity of the targeted Elk-Antelope fields to the Purari River would likely prove beneficial in enabling cost-effective transport of equipment and people to the relatively flat upstream terrain at the gas fields. The site is also much closer (approximately 330 km) to the proposed gasification and shipping terminal, requiring less time and money for pipeline construction. Meanwhile, the LNG plant would be located adjacent to the existing PNG LNG plant, allowing for potential integration and joint cooperation.

Covering its bases, the joint venture is also engaged in fulfilling its other administrative obligations. This entails completing all the minutiae of the approval process under the Mining Act, including carrying out the requisite studies and consultations, such as environmental impact statements and social assessments required by the Mineral Resource Authority (MRA). The government is expected to vet these by 2018, at which point all stakeholders, including the commercial project partners, landowners and the government, will work out a contract that contains benefit agreements suitable for all parties. Only once all of these elements have been completed will the MRA issue the necessary petroleum development licences (PDLs). These PDLs should kick off mine operations, with the first shipments expected to sail by 2022 if all goes according to plan – 10 years after the initial investment by Total in 2012.


Speculation over the future development of isolated prospects in Western Province, just west of the active PNG LNG fields, was addressed after ExxonMobil and the government signed a memorandum of understanding (MoU) in January 2015 for the development of the highly prospective P’nyang field. Located in petroleum retention licence (PRL) 3 to the north-west of the Hides field, the agreement outlines a plan to pipe natural gas into the existing PNG LNG infrastructure for production support, including production optimisation and unblocking of the existing two trains, a potential third LNG train, and the supply of electricity and gas for domestic power. The MoU is also significant in that it established a framework and timeline for the awarding of a PDL for the site in the future, which was applied for by the joint venture in 2015 and sets a deadline for the FID on the third PNG LNG train by 2017.

If approved, the upstream development of P’nyang would include new gas and liquid pipelines that tie into existing project infrastructure at Kutubu. The pipeline route, which was already established in 2015 – a condition of which was to supply at least 25 MW of electricity to the Port Moresby grid – may help facilitate the development of stranded gas fields in the western fore-lands. Meanwhile, Further exploration is being carried out, with the evaluation of new seismic and well data altering estimates of gross 2C contingent gas resources for the field in 2015 to 3.5trn scf, up from previous estimates of 2.6trn scf.

Exploring The Options

For stakeholders in the PNG LNG project, this incorporation into the existing brownfield operation represents the optimal outcome, as it provides new and potentially large reserves of feedstock for the project. It is not, however, the only developmental option explored for the fields in the area. Horizon Oil, along with Repsol Oil and Gas (formerly Talisman Energy prior to the May 2015 buyout), Eaglewood and Osaka Gas, among others, hold shares in a handful of PDLs and PRLs in the area just to the south of P’nyang and west of the PNG LNG fields. In these locations they have been exploring the option of starting greenfield projects linking up the various disassociated fields, including Stanley, Tingu, Ketu and Elevala in the vicinity.

Along with joint venture partners Repsol (44.45%) and Osaka Gas (22.22%), the Stanley field – operating under the 324-sq-km PRL 4 – contains significant certified natural gas resources. To the south-east of this is the larger PRL 21 site, which encompasses a total of 729 sq km, including the Elevala, Ketu and Tingu gas fields held by Horizon Oil (21%), Repsol (32.5%), Osaka Gas (18%), Kina Petroleum (15%) and Mitsubishi (7.5%). In all, the Elevala, Ketu, Stanley and P’nyang fields are projected to contain approximately 5trn scf of wet gas, more than enough for a standalone project, with many of the sites within easy reach of the navigable Fly River, PNG’s second-longest river.

Also of note in the area is the development of the Stanley Gas project in PDL 10, located adjacent to PDL 4, which is planned to monetise associated condensate with domestic gas sales to nearby mines starting with Ok Tedi, the country’s largest mine. Now headed by Spain’s Repsol, with a 40% share of the project, along with partners Horizon Oil (30%), Osaka Gas (20%) and Mitsubishi (10%), the site contains gross 2C resources of 322bn cu feet along with 10m barrels of condensates. Repsol has indicated that initial development will focus on a GTE power plant to supply the Ok Tedi mine and surrounding townships with electricity, followed by transporting liquid condensates to the Napa Napa refinery for processing.

Oil Production

Crude oil production in PNG continues to be the sole domain of the well established oil and gas producer Oil Search, which holds majority stakes in all the country’s producing petroleum licences as well as acting as operator of the wells. Petroleum output from the maturing fields has continued to decline over the years, although the operator has made considerable efforts to stabilise output by employing a variety of more efficient oil recovery techniques to stem the losses leading up to the initiation of the LNG project and the associated condensates it brings. These optimisation efforts led to a slight drop-off in crude production in the country, from 30,107 barrels per day (bpd) in 2014 to 28,041 bpd in 2015, a 6.9% decline. The top performer continues to be the Kutubu complex of oil fields, which actually boosted its output 3% on the year with gross production averaging 17,325 bpd in 2015, compared to 16,843 bpd in 2014. By contrast, gross production from Moran in 2015 averaged 8635 bpd, down 22% from 2014 levels, largely because of natural declines in the Moran 2X ST2 and NW Moran 1 ST5 wells. Production from the Gobe Main field averaged 827 bpd, down 5% from 2014, along with the SE Gobe field, which averaged 1255 bpd, down 8% from 2014 levels.

Offsetting the natural declines in the oil fields despite of ongoing reservoir management practices is the substantial increase in liquid condensates collected from natural gas operations in the area. The production of total liquids derived from the PNG LNG project spiked 67% on the year from 18,520 barrels of oil equivalent per day (boepd) in 2014 to 30,921 boepd in the first full year of production. These were further supplemented by 306 boepd from the Hides GTE facility in 2015, down slightly from the 331 boepd recorded in 2014.

Ships Away

In terms of exports, crude oil shipments have declined in recent years, dropping from 13.8m barrels in 2007 to 8.2m barrels by 2014 and 6.6m barrels in 2015, in part due to the lower production rates at the Kutubu, Moran and Gobe fields. The average export price of crude oil was PGK143 ($48.82) per barrel in 2015, a decline of almost 44% year-on-year. However, these figures were bolstered by the addition of condensates captured from the PNG LNG project, which began producing in June 2014, totalling 3.5m barrels of oil equivalent (boe) in 2014. Once the production line ramped up to higher capacities, the amount on condensate more than doubled in the first nine months of 2015 to 7.8m boe, according to the latest data from Bank of PNG, the central bank.

Keeping The Lights On

With some 462,840 sq km of rugged territory criss-crossed with craggy mountain ranges, meandering rivers and large stretches of ocean to negotiate, providing electricity to PNG’s roughly 7m liberally dispersed residents has proven a challenging task for the country’s utilities providers over the years. The task of bringing power to the people falls largely on the shoulders of state-owned utility PPL, along with Western Power, a wholly-owned subsidiary of PNG Sustainable Development Program, operating a series of smaller systems in Western Province along with a handful of other smaller, privately operated grids serving isolated population pockets. In all, the country operates a total grid generation capacity of approximately 400 MW, 45% of which is hydropower, providing electricity to around 12% of the population (see analysis). To meet its developmental goals of extending electricity to 70% of the country’s population by 2030, the company has rolled out its own initiatives such as the Rural Electrification Project as well as partnering with donor agencies. These include a series of projects from the Asian Development Bank, consisting of the ongoing Town Electrification Investment Programme, with an initial tranche of $62.07m running through to June 2017 and additional planned funding of $73.6m; the $65.39m Port Moresby Grid Development project, running until July 2017; $1m for the implementation of the electricity industry policy, which finished in June 2016; and another $5m for improved energy access for rural communities, also running through to July 2017. The World Bank is also chipping in with its $8.35m PNG Energy Sector Development Project.

Looking For Suitors

Two companies have been responsible for the vast amount of exploration and production activity that led to the country’s modern revenue generating energy sector: InterOil and Oil Search. Together they have financial interests linking them across the hydrocarbons value chain, from early exploratory efforts in dozens of tenements and the development of oil and gas fields to the exporting of LNG shipments, the refining of crude at Napa Napa and the retail sales of petrol at petrol stations. However, after InterOil’s revenues began tailing off as oil prices declined from more than $100 per barrel in August 2014 to less than $30 in January 2016, the company began looking for suitors.

Highest Bidder

The attractiveness of the exploratory licences still held by InterOil in the country’s high-potential regions, particularly in areas that are near to existing and planned LNG projects, led long-time rival Oil Search to offer up a $2.2bn bid for the company in May 2016. However, in late-July 2016 ExxonMobil agreed to acquire InterOil for more than $2.5bn and for up to $3.6bn. ExxonMobil will now pay between $45 and $71.87 per share, depending on how much potential gas there is at the Elk-Antelope fields, in which InterOil owns a 36.5% stake. “ExxonMobil will work with co-venturers and the government to evaluate processing of gas from the Elk-Antelope field by expanding the PNG LNG project,” the oil giant said in a public statement in July 2016.


Bucking international trends which have seen many oil and gas producers shutter their facilities and plug their wells, the relatively low production costs and close proximity to desirable Asian markets are allowing PNG operators wait out the commodity cycle downturn. “The cost structure of production in PNG is much lower than other countries like Australia, for example, as there are no unions in the energy sector here, while labour continues to be much cheaper,” Sonk told OBG. “That is why there is still a lot of interest in PNG as international buyers continue to be very keen about our production.”

This trend should continue given PNG LNG’s guaranteed offtake agreements and the expected recovery of the spot market. Meanwhile, the development of the Papua LNG project will likely provide a boost as early as 2022, in terms of both export revenue and bringing greater supplies of natural gas to the domestic market.

In the longer term, the country still contains vast areas of under-explored potential, with the discoveries in Western Province most likely to serve as the bridge between the current LNG projects and those which have yet to be realised. Downstream refining operations are also in the midst of a significant overhaul, which should allow for the greater processing ability of domestic liquids.

In terms of electricity, the private sector is making encouraging overtures towards greater participation in the generation sector, and anticipated future domestic gas supplies should prove to be beneficial. However, significant improvements in both generation capacity and the electrification ratio have yet to be properly implemented in PNG.

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The Report: Papua New Guinea 2016

Energy chapter from The Report: Papua New Guinea 2016

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