Ready for next wave of LNG

 THE current outlook for liquefied natural gas (LNG) is challenging. Spot LNG prices are significantly below long-term contract prices, which in turn are much lower than what they were in 2014.  

In  addition  to  low  LNG  prices,  the  industry  will  be  burdened  by  excess capacity until 2020, at least. 

Despite the current gloom, no one seriously doubts that LNG demand will continue to grow, or that the mid-term growth will continue to be in Asia. New LNG development will therefore occur, but where? 

The US is the most obvious location due to its infrastructure and resource advantages, but Papua New Guinea is among the best positioned of the other locations. PNG is well-positioned across several criteria – resources, fiscal regime, geography and government support.

Price and market issues aside, PNG is very well-placed for LNG investment:

• Both brownfield and greenfield development options;
• at least three, possibly four, development zones;
• most resources are onshore. Onshore development is generally cheaper than offshore;
• PNG is “wet gas” prone. This substantially improves project returns through both the higher heating value of the LNG and the project’s associated liquids revenues;
• proximity to the high-priced Asian market;
• favourable and stable fiscal regime;
• strong LNG operating experience of Exxon and Total, with the potential for a new entrant, and,
• The successful implementation of the PNG LNG project, which started up ahead of schedule and did not experience a large cost overrun. The project was viewed as politically, logistically, and technically challenging. PNG LNG’s track record, and proven access to finance, adds to the credibility of PNG for further development.

The importance of resource development to PNG

In  addition  to  being  well-positioned,  an  expansion  of  LNG  investment  may  be viewed as an economic imperative by the PNG Government. PNG is resource dependent. It has a history of sporadic bursts of growth that have petered out. National growth was heavily dependent on the futures of the Bougainville and Ok Tedi mining developments. 

Bougainville was closed down due to civil unrest and Ok Tedi did not reach its full potential because of environmental issues. 

Some commentators are now saying that the economic boom promised by the PNG LNG project is vanishing due to low prices and a poor outlook for LNG demand. 

The likely response to this threat to growth is that the PNG Government will attempt to ensure that the fiscal and regulatory conditions are as conducive as reasonable to promote further gas development.

The Government has initiated the creation of the National Petroleum Corporation of PNG.   

NPCP will be the holder of government interest in all petroleum and gas resources in PNG.  

There was previously another entity: Petromin, which claimed a role as the national oil company. 

However recent legislation has en­shrined NPCP, which will be rebranded “Kumul Petroleum”, as the only legitimate national oil company of PNG. Kumul Petroleum has large assets and the right to back-in up to 20.5 per cent in all new LNG developments.  

It is poised to assume increasing importance in the oil and gas sector in PNG and is the key vehicle for the Government to play a critical role in LNG development in PNG, and thus will become a force to contend with in PNG. Government revenue from the PNG LNG project is primarily linked to return on investment, not revenue, in the near term. 

However, over the life of the PNG LNG project, the contribution from taxation is greater than the state’s returns on investment, even with low oil prices.  

The timing of PNG LNG’s taxation payments is related   to   reven­ues,   financing   arrangements   and   de­preciation   policy,   with payments   likely   to   start   from   2017.   

The   PNG   Government   budgeted   for US$89.70/bbl (K252.29) oil price in 2015, but it is seeing some revenue upside from higher- than-expected PNG LNG production and the falling value of PNG’s kina currency versus the US dollar.  

As a consequence, 2015 government revenue is now expected to be 10 per cent less than the amount forecast in the 2014 budget. 

The shortfall escalates to 20 per cent for 2016 and 30 per cent by 2018. The 15.5 per cent GDP growth forecast for 2015 has been reduced and is expected to slow to 5 per cent in 2016. Despite the less than anticipated boost to government revenue, if PNG wants to retain its growth ambitions, it has little alternative but to continue resource development. 

As a consequence, PNG is likely to continue to offer terms that are conducive to additional investment. PNG already has one of the more favourable resource taxation regimes globally.  The Australian Government is a key foreign supporter of PNG and may help PNG resource development.

PNG hydrocarbon resources

PNG  has  several  highly  prospective  hydrocarbon  areas. All  are  in  the  western portion of the country and either in the Highlands or on the southern flank of the Highlands. PNG’s Kutubu crude oil production began in 1992 and the Hides Gas-to-Electricity (GTE) project started gas production in 1991.

Highlands hub

The 6.9 million tonne per annum (mmtpa) PNG LNG project started in 2014 with the first train in the two-train development commissioned in April and the second in May. 

The indicative capital cost was US$19 billion (K52.7bn). 

Gas is piped from the Highlands to the coast and then via a sub-sea pipeline to near Port Moresby with approximately 400 kilometres of the approximately 700km pipeline offshore.  Gas is extracted from the Hides, Angore, and Juha gas fields, plus associated gas from the existing Oil Search-operated Kutubu, Agogo, Gobe Main and Moran oil fields. Total recoverable gas is estimated at over 9 trillion cubic feet (tcf) with over 200 mmbbls of liquids. 

This is sufficient to supply the current 2-train LNG development for over 30 years, excluding any debottlenecking. Additional gas reserves will be required if the project is expanded by a third train, however the region has high potential for additional gas discoveries.

The  participants  in  the  project  are  ExxonMobil  33.2 per cent,  Oil  Search  29 per cent, Santos 13.5 per cent, and JX Nippon Oil 4.7 per cent, with the PNG Government owning the remaining 19.6 per cent, including ownership on behalf of PNG landowners.

Northwest hub

The P’nyang discovery is in the PRL 3 permit, 100-150km northwest of the main PNG LNG gas fields. It is a potential source of additional gas for expansion of the PNG LNG project. P’nyang has recoverable resources of approximately 3.5 tcf with significant exploration potential nearby. The unrisked resource assessment of the nearby permits is 11 tcf; however, specific discoveries are likely to be small/mid-sized and less than 1 tcf. 

Similar to much of PNG, the gas in the region is “wet” and the high liquids content   of   the   gas   field   could   significantly   improve   development economics. The participants in PRL 3 are ExxonMobil 49 per cent, Oil Search 38.5 per cent, and JX Nippon 12.5 per cent. 

There has been recent speculation about Santos acquiring a 10-15 per cent interest in this permit with all existing permit holders expected to reduce their current equity. 

If this occurred, it would increase the likelihood that P’nyang gas could be used to support an expansion of the PNG LNG project because ownership in the respective gas resources would then be similar.   

The P’nyang license was due to expire  in April 2015, however ExxonMobil applied for a Development License in February, which is being considered by the PNG Department of Petroleum and Energy.  

The partners in the PRL 3 license, in which the P’nyang gas field lies, must commit to develop P’nyang by end-2017 otherwise they will lose the licence. The PNG Government, NPCP, and Oil Search are keen on the third train, however ExxonMobil has a policy of not committing to building LNG trains until sufficient reserves at P-1 level have been proven. As it stands, the P-1 gas might only be enough for seven years  and while another company might have risked going forward, banking on new discoveries to support the third train, EOM requires certified reserves for a longer period than this.  

A firm decision on a third train’s final investment decision (FID) is expected in 2017.

• Continued tomorrow