The long wait for the Papua New Guinea liquefied natural gas (LNG) project is now over, and the energy sector is transforming from a major investment vehicle into a primary revenue generator for the economy. In fact, the project is expected to have so much of an impact during its first full year of LNG exports that PNG was projected by the Economist Intelligence Unit to lead all Asian economies in revenue growth in 2015 at nearly 15%, with the Asian Development Bank forecasting an equally robust 15% expansion.
While these projections have since been tempered by a decline in global oil prices of around half from 2014 to 2015, leading to a reduction in the government’s own budgetary forecast from 15% to 6.9%, the successful completion of the PNG LNG project has triggered a wave of optimism within the country. Driven by the $19bn investment in PNG LNG, the oil and gas sector has been the largest single contributor to the economy, which expanded 93% from $7.9bn to $15.3bn during the peak expenditure years of the project from 2010-13.
While the long-term trends are positive, short-term dynamics in the market have definitely been affected by the downturn in energy prices that began in mid-2014. Peter Botten, the CEO of Oil Search, told OBG, “Everybody is reviewing investment spends and marginal projects will be stalled in the present business environment, like the Stanley project in PNG. If cash flow is down, investments are down too, while equity funding has diminished considerably. Small companies will struggle to find money and it will have a significant impact on exploration on the short to medium run.”
Lay of the Land
Oil Search may be listed in Australia, but it has been involved in oil and gas operations in the country as far back as 1929. The company has parlayed its local expertise into stakes in key oil and gas projects in PNG and remains the sole operator for all existing domestic crude oil production.
Oil Search is also the second-largest stakeholder in the PNG LNG project with a 29% share, behind operator ExxonMobil’s 33.2% stake, and it recently managed to secure a 22.8% share in the sector’s next big thing, the Elk-Antelope LNG project. The latter project also managed to attract a second energy supermajor, with France’s Total signing on to head the project, which is being touted as one of the most profitable such developments currently under way.
In part due to the project being sourced from one large gas field, instead of numerous smaller fields, as is common in other projects, the cost of the Elk-Antelope project is estimated at $2051 per million tonnes of LNG capacity, well below the cost of $2324 per million tonne under the newly completed PNG LNG near Port Moresby, according to InterOil. The project also benefits from being located some 350 km closer to Port Moresby than the PNG LNG fields. “Independent analysis suggests Elk-Antelope is the most competitive new-build LNG project globally, with the potential for superior returns even at low commodity prices,” Michael Hession, the CEO of InterOil, told energy publication Platts in March 2015. Bernstein Research echoed the sentiment, saying, “While investors worry about the economic viability of LNG in a lower price oil environment, Antelope is among the most competitive projects coming to market. If Antelope can’t make it, nothing else will.” Botten told OBG, “The additional demand for gas will come mainly from Asia over the next 15 years, and PNG, thanks to the Elk-Antelope field, is ideally placed to take advantage of this exceptional growth.”
Despite the challenges, which have particularly affected smaller exploration and development firms, several of the more nimble companies remain active. Canada’s Talisman Energy (since bought by Spain’s Repsol) and Australia-based Horizon Oil are leading the charge in what is expected to be the third major project to take place in Western Province. Other active players include US-based InterOil, Jersey’s Heritage Oil, Australia’s Santos, Japan’s JX Nippon Oil and Gas Exploration Corporation, Osaka Gas, Mitsubishi, PNG’s Kina Petroleum and Canada’s Eaglewood Energy (since bought by Australia’s Transform Exploration).
Way of the Dinosaur
PNG’s energy sector may have been founded by intrepid geologists and roughnecks slogging through the jungle in search of a few thousand barrels of crude oil, but the days of striking it rich by digging for black gold are now far removed. Crude production at the country’s existing mature oilfields has long been in decline, with most near-term prospects for new liquid energy coming from ancillary production at new natural gas plays. But while the overall crude output has declined over the past decade, falling about 35% from 46,689 barrels per day (bpd) in 2007 to 30,107 bpd in 2014, recent exploration and technical overhauls of ageing fields have resulted in moderate production increases over the past few years.
Total crude production edged upwards 1.7% to 30,107 bpd in 2014 for a total of 5.85m barrels for the year compared to 29,604 bpd and an annual total of 5.7m barrels in 2013, although this is well off the 8.26m barrels produced in 2007, according to operator Oil Search. The most productive operation remains the Kotubu field, producing 3.69m barrels of oil in 2014, up from 3.47m barrels the previous year. In 2014 this was followed by Moran with 1.99m barrels, with smaller contributions from SE Gobe (127,000 barrels), Gobe Main (32,000 barrels) and SE Mananda (5000 barrels).
Botten told OBG, “There is a lot of uncertainty in the market at the moment, but the good news is that producing in PNG continues to be a profitable exercise, even considering the current oil price. Improving efficiency from now on though will be the name of the game.”
Now that LNG cargoes are sailing regularly from the marine terminal in Port Moresby, the race is on for prospectors searching for the next wave of energy reservoirs to tap. The Elk-Antelope play, led by Total, is easily the most advanced and could begin major construction works within the next few years. Close on the heels of this development is an ambitious plan to develop a series of oil and gas fields in the rugged Western Province by a collection of operators headed up by Talisman Energy. Still in the exploratory stages, the Western Province project aims to stitch together more than a half dozen exploration and production (E&P) licences located to the west and south of the Hides gas field. These include petroleum prospecting licences (PPLs) 223, 372, 373 and 430, along with petroleum development licence (PDL) 10 and petroleum retention licences (PRLs) 4 and 21. All of these are majority held by either Horizon Oil or Talisman, which have stakes ranging from 30% to 100% in each prospect. Risk is further spread among a number of other firms with minority stakes in the tenements, which include: Osaka Gas with shares in four licences ranging between 10% and 22.22%; Mitsubishi, which has stakes in two licences; Eaglewood with two licences and stakes of 45% and 50%; P3 Global Energy with one 10% stake; and Kina Petroleum with one licence.
After wells drilled in the Elevala and Ketu fields in 2011 and 2012, respectively, yielded promising results, the Tingu-1 well was spudded in August 2013 to determine the depth, thickness and quality of the Elevala Sandstone reservoir within the Tingu-1 structure, as well as to prove hydrocarbons’ fluid type and column height, according to Horizon Oil. The well encountered a gas water contact in the Elevala Sandstone consistent with that in the Elevala accumulation to the south-east, implying a connected field of considerable size. The find also revealed a flow rate of up to 48m standard cu feet (scf) per day, with no water and a condensate-to-gas ratio of approximately 65 barrels per 1m scf.
Other exploration activity carried out by Talisman in 2014 included two exploration wells, Manta-1 and NW Koko-1, along with the acquisition of 7600 sq km worth of airborne gravity magnetic data, another 12,467 sq km of lidar data and other seismic data from PPLs 269, 287 and 426. Another two development wells, Stanley 3 and Stanley 5, were also sunk in the Stanley field, which is planned for the first stage of extraction and sales. Additional activity scheduled for 2015-16 includes: completing the first and second seismic programmes in PPL 269; drilling up to four new wells in the foothills and foreland areas starting in the third quarter of 2015; completing gradiometry studies on PPL 287 and PPL 426; and using the data to plan seismic campaign covering approximately 200 km starting in the third quarter of 2015.
The project targets not only mid-range LNG exports of around 2m-4m tonnes per annum, but also significant sales to the domestic market. This would take place primarily through the sale of natural gas to the nearby Ok Tedi mine, which recently extended its mine life through 2025 and would gladly take on natural gas supplies to replace the more expensive and dirtier diesel fuel currently powering the site. The nearby Frieda River prospect offers another potential major purchaser once the project is given the final go ahead by the government. Overland export to Indonesian towns in West Papua such as Merauke and Jayapura is another possible option. In terms of additional export potential, the mid-range project could tie in the various fields with pipelines to a yet-to-be determined location for shipping, with the coastal areas of Daru Island, Cape Possession, north-west of Port Moresby, and Site 152, also situated just outside of Port Moresby, all being discussed as possible terminals. Another option under consideration is to use reserves to supply a third train to the PNG LNG project, mitigating the need to build redundant processing and transport infrastructure.
The Search Continues
Santos, Australia’s largest domestic producer and a PNG LNG stakeholder, is also expending considerable time and capital on exploratory efforts in the country. From the second quarter of 2013 to the same period in 2014, the company significantly expanded its exploratory acreage, acquiring four new onshore exploration licences for PPLs 261, 269, 287 and 426, as well as the offshore prospect of PRL 38. Much of these efforts are focused on the Northwest Shelf, which extends across the Papuan Basin and shares petroleum with other basins developed in Australia, including the Carnarvon and Browse reservoirs.
But while the Carnarvon system has been more heavily scrutinised – some 800 exploratory wells have been drilled over its total area of 376,000 sq km – the Papuan Basin is believed to still hold undiscovered resources, with only around 160 wells drilled in an area that spans a total of 276,000 sq km since 1950.
Wapu Sonk, managing director of the National Petroleum Company of PNG (NPCP), pointed to the potential in the Eastern Papuan Basin in particular, telling OBG, “There is definitely great excitement about the development of the Eastern Papuan Basin compared to the Western Papuan Basin. It is easier to drill there and cheaper thanks to the network of rivers which allow the shipment of equipment and personnel by barge.”
So far the most successful geology explored has been the foldbelt inversion zone running north and west from the Elk-Antelope field that contains proven finds including Hides, Gobe and Mananda, as well as other exploratory fields such as P’nyang. The foldbelt has experienced a 38% exploratory technical success ratio, according to Santos, and currently accounts for more than half of the country’s recorded cumulative hydrocarbons resources. Tertiary carbonate plays, which include Elk-Antelope, Pandora, Pasca and Uramu, have also shown potential, albeit at a lower technical success ratio of 20%. The foreland plays Elevala, Stanley, Douglas/Puk Puk, Langia and Manta have exhibited a 33% technical success ratio, although the fields are more fragmented, leaving a significant amount of stranded gas and making them more expensive to develop.
Taken together, this early data suggests a number of options. These include integrating the foreland discoveries into the existing LNG infrastructure, or investing $1.5bn to drill another 25-odd wells to find an additional 2.5trn scf of gas to add to the 2.7trn scf already discovered. Promising results from the foldbelt and carbonate plays have so far shown potential for each of them to develop into stand-alone LNG projects.
Activity in the energy sector is currently being supported by the government through the Oil and Gas Act of 1998, which was modified by the Oil and Gas Regulation of 2002. Other secondary regulations, such as environmental laws, also apply to the sector. E&P activities are regulated by the Department of Petroleum and Energy (DPE), which is responsible for evaluating applicants and issuing five types of licences on a first-come, first-served basis. The two most widely used are the PPL, which is issued for exploration activity, and the PDL, which is given to companies wishing to engage in the development and production of petroleum or natural gas. PPLs are valid for an initial duration of six years and may be renewed for another five-year term, although extensions only cover 50% of the territory included in the original area. Companies may apply for anywhere between 60 and 200 graticular blocks, which are defined as 81 sq km.
With a validity of 25 years, PDLs are valid for a much longer period of time and grant firms development and production rights, which may be extended for a maximum of 20 more years. Other permits include the PRL, petroleum processing facility licence and pipeline licence. For each licence applicants must fulfil three criteria: demonstration of adequate financial capacity, a work programme that links to a budget and demonstration of a qualified technical team, after which applications are reviewed by the DPE.
Law & Order
To ensure that issued licences are being actively worked by qualified personnel – as opposed to speculative holding of licences – the government has taken steps in recent years to streamline the administrative process and hold licence holders more accountable for inactivity. A review was completed in 2014, and Nixon Duban, the new Minister of Petroleum and Energy, announced that the vast majority of licence holders were not adhering to their planned development schedules.
The findings revealed that half of all PPLs were not in good standing with the DPE and had unfulfilled work programmes and expenditure commitments, outstanding technical reports and outstanding rental, annual fees and penalties totalling PGK50.6m ($19.15m). PRL licences fared little better with six of 13 holders found to be underperforming while amassing outstanding fees and penalties of just over PGK1m ($378,400). Only one out of 10 PDL holders was in good standing in terms of remaining current on fees and payments, while two of the 10 were up to date on furnishing technical, biannual, annual and other operational reports.
As a result, Duban announced a number of new recommendations to ensure projects will not languish. Some of the more substantial potential changes include: amending the Oil and Gas Act to increase punitive measures for non-compliance; increasing the DPE’s prosecution powers; refusing permits for underqualified and underfunded firms; capping the number of blocks awarded to companies based on their capacity to develop them; and converting the DPE into a strong sector regulator with advanced geological database systems to better monitor and enforce regulations.
In addition to these proposed administrative changes, the government is continuing its evolution of the ownership structure of state-controlled stakes in various mineral and energy projects as mandated via an Oil and Gas Act provision that grants the government the right to acquire an equity stake at cost in any project of up to 22.5% for petroleum.
In the past these equity share were held either by state-owned companies Petromin PNG Holdings or the Independent Public Business Corporation, but these entities are currently being dismantled and their assets remain in the process of being folded into the new Kumul Petroleum Holding. Kumul will act as a steward for the commercial aspects of these projects on behalf of the government, while a new Petroleum Regulatory Authority would handle regulation and oversight.
The completion and full operation of the PNG LNG project ahead of schedule has proven that large-scale energy projects can succeed in PNG. Although revenue flows for the state are likely to be significantly less than anticipated due to declining oil prices, PNG’s plentiful untapped reserves and resolve to become a major regional gas exporter look to provide ample incentive and means to move forward with at least one, if not more, LNG project. Exploration for the Elk-Antelope play in particular has shown promise, and majority partners have so far displayed a willingness to fast-track plans. Botten told OBG, “By end-2015 there will be a good understanding of the size of the Elk-Antelope field, so that we can start thinking about two additional trains close to PNG LNG. The final investment decision will be made by the end of 2017.”
Although most of the off-take in earlier stages of development will be destined for foreign shores, PNG’s relatively modest energy demand could easily be met by the diversion of gas and condensates. This would help alleviate electricity shortages and facilitate broader efforts to boost the rate of electrification.
Sonk of the NPCP told OBG, “A study by McKinsey showed that there is direct correlation between the rate of household electrification and the GDP growth of a country. When the rate of electrification reaches 60-70% of the population, GDP growth starts to become exponential and the country reaches middle-income status, which is the Vision 2050 target for PNG.”
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