The country’s limited energy needs and its rapidly expanding supply of gas have led policymakers to pursue the somewhat obvious path of focusing on the export market via shipments of liquefied natural gas (LNG). Although the price of energy has declined considerably since the initial plans for the Papua New Guinea LNG project were first drawn up, gas remains the country’s top foreign currency earner, with future potential earnings having the power to transform the economy. With one major LNG project now up and running, a host of energy firms both large and small are looking to develop the next big play in the country.
Capable of producing 6.9m tonnes per annum (tpa) of gas for export, the PNG LNG project was initially anticipated to account for most of the state’s projected PGK698.5m ($264.31m) in mining, petroleum and gas dividends within the non-tax revenue component of the 2015 national budget. Additional mining and petroleum taxes levied on the LNG project were also projected to make up a substantial portion of the estimated PGK1.75bn ($662.2m) total extractive resources taxes in 2015, making the project a disproportionally large component of projected revenue. Although these estimates now appear to overstate future revenues due to the decline of oil and gas prices well below initial assumptions of $90 per barrel, the sale of gas to other regional buyers should still be enough to stem the decline of resource revenues. The government’s revenues have decreased from more than PGK2bn ($756.8m) in 2011 to PGK700m ($264.88m) just two years later, according to a paper published in December 2014 by Paul Flanagan, former chief advisor at the Australian Treasury.
ExxonMobil’s $19bn investment consists of two production trains located at its liquefaction facilities near Port Moresby, which are fed by a gas pipeline snaking its way down from the highlands. The integrated development includes gas production and processing facilities spread out across the Southern Highlands, Hela, Western, Gulf and Central Provinces. All told, more than 700 km of pipelines connect the project facilities, including a gas conditioning plant in Hides and liquefaction and storage infrastructure on the coast.
ExxonMobil holds a 33.2% operating stake in PNG LNG, along with joint venture partners PNG-based Oil Search (29%), the state-owned National Petroleum Company of PNG (NPCP, 16.8%), Australia’s Santos (13.5%), Japan’s JX Nippon Oil and Gas Exploration Corporation (4.7%), and local player Mineral Resources Development Company (2.8%).
After ramping up production ahead of schedule in April 2014, the LNG plant delivered its first cargo in May, well ahead of the initial target of October. By end-June 2014 it had loaded seven LNG cargoes, all of which were sold on the spot market. Around 95% of the project’s capacity is accounted for via long-term contracts, which commonly set prices to rolling 10-year averages and which kicked in during late 2014. These long-term customers include China’s Sinopec with a commitment for 2m tpa, Tokyo Electric Power Company with 1.8m, Japan’s Osaka Gas at 1.5m and Taiwan-based Chinese Petroleum Corporation for 1.2m.
With full-scale production now achieved, the partners are looking to boost their returns by adding a third LNG train to the liquefaction facilities. Wapu Sonk, managing director of the NPCP, told OBG, “In the short run there are good possibilities for three additional LNG trains in PNG, one as an expansion of the existing facilities and two more from the InterOil-Total gas project to be developed in the Gulf region, even though the initial geological data are showing reserves that could allow three or even four additional trains.”
The greatest potential for sourcing the additional gas is reserves in the Hides field, in which the joint venture has been drilling exploratory wells in the Hides Deep prospect. Another potential source of gas used to underpin production is the nearby P’nyang gas field.
PNG may not have to wait long for its next natural gas project to kick off, with work well under way to assess the viability of a second major LNG export-oriented project supported by what could potentially be the largest single energy reservoir discovered in the country to date. The Elk-Antelope prospect located in the Gulf Province has been receiving considerable attention of late from project developers led by major French oil company Total. As new data and testing continues to roll in from the fields, projected estimates continue to increase, with accessible reserves projected by partner US-listed InterOil at 6.47trn-10.44trn standard cu feet (scf) of initial recoverable gas in early 2014 and up to an additional 17trn scf from other nearby associated fields.
Appraisal of the project’s primary wells was accelerated in late 2014, with early results from test wells showing considerable promise of being able to support a multi-train LNG project. Tests on the Antelope-4 well intersected a reservoir at just more than 1911 metres and indicated high-quality reservoir porosity and permeability, resulting in general good reservoir quality extending into the southern flank, according to InterOil. The Antelope-5 tests, which reached a depth of 2307 metres, revealed the best reservoir in field to date in thickness, quality and fracture density with a gas column of approximately 680 metres, with the structure and density giving it considerable upside potential to the west of the field. The spudding with Antelope-6 is projected for the second half of 2015 and is expected to provide additional data regarding structural control, reservoir properties and the extent of dolomitisation towards the east side of the play. InterOil estimates the Elk-Antelope field has 9.9trn scf.
The Elk-Antelope reservoir is not the whole story, however, as the site is encircled by a mosaic of exploration licence tenements, many of which are currently under scrutiny. These include the Bobcat, Raptor and Triceratops fields to the north and west, the latter of which underwent assessment in the first half of 2015. The combined gross, unrisked contingent resources thought to be contained in these fields is estimated by InterOil at roughly 8trn scf. All three exploration licences are majority held by ElkAntelope partner InterOil, increasing the likelihood of a project extension should the satellite fields prove profitable. Another 9trn scf of gross, unrisked prospective resources is projected to lie in Antelope-South and the Wahoo field to the south-east. Drilling at Wahoo and Triceratops began in June 2015, and the joint venture partners are expected to choose a preferred development model soon. Early works would begin in the third quarter of 2016, with a final investment decision and the start of construction set to follow a year later.
While the geology and exploration of the project may be straightforward science, assessing the ownership structure has proven more complicated. The Elk-Antelope field was originally operated by InterOil under a 2009 project agreement with the PNG government to deliver a 7.6m- to 10.6m-tpa LNG project. When InterOil and the government came to loggerheads over the plan to develop smaller LNG projects in stages, which the government disapproved of, the company responded by opening negotiations for a stake in the project with international heavyweights ExxonMobil, Shell and Total. While Total was awarded the contract in late 2013 and the deal finalised in March 2014, a spanner was thrown into the works when long-time PNG operator Oil Search bought out one of InterOil’s joint venture partners, Pacific LNG Group Companies. Pacific LNG held a 22.8% stake in Elk-Antelope, and as such Oil Search claimed pre-emptive rights relating to the subsequent joint venture and sought arbitration. The case was heard at the end of November 2014, with Total named project operator after agreeing to pay $401m for its 40.1% stake in the project. This left InterOil with a 36.5% share and Oil Search a 22.8% interest, with remaining holdings split among minority owners. Under the terms of its acquisition, Total is required to make further pay-outs to partner InterOil dependent upon the size of the gas resource. Should the resource be determined at 7.1trn scf of gas, the certification payment would be $580m, with the payments scaling up for larger volumes.
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