Bottom Line: PNG starts to enjoy benefits

HOME

BUSINESS

SPORTS

EDITORIAL

LETTERS

COLUMN 1

Getting serious over LNG

The clarity that we see on the mining scene is not as discernible when it comes to oil and gas.
The two liquefied natural gas projects that are on the drawing board are of a much bigger scale than any project contemplated in the past, in terms of capital expenditures as well as export generation.
However, we have learned from the Gas Pipeline Project experience that there can be ‘many a slip between the cup and the lip’ as they say.
Something that many people, even those fairly well versed with the subject, have not recognised is that during most of the era that the gas pipeline to Australia was planned, it simply was not feasible to use gas from Southern Highlands for LNG.
The economics just did not work out.
What has changed in dramatic fashion is the cost of crude oil, which has a close linkage with LNG prices.
At that stage, the gas pipeline to Australia was the only commercial proposition for PNG’s “stranded gas”.
LNG has become viable in the intervening period only because LNG prices have since risen four-fold to around US$8-9 a gigajoule.
Why would a gas consortium sell natural gas to commercial and residential users in Australia for US$3 a gigajoule, in a highly competitive domestic market, when newer LNG customers are willing to pay three times as much?
It was also during the period that the pipeline was planned that major new coal bed methane reserves were proved up in Queensland, where it could soon also be used to produce LNG for export.
One has to recognise the size and complexity of an LNG operation – each of the PNG plants would cost around US$10 billion.
The risk of cost overruns are very real these days in virtually all the 14 countries that produce LNG; inadequate assessments of recoverable gas resources could literally blow a project out of the water and corporate customers in Japan and other countries are always concerned about political and sovereign risk.
The latter is why project proponents such as ExxonMobil and InterOil’s Liquid Nuigini Gas will not make any substantive moves without first having in place a long-term fiscal agreement with the government.
Both LNG proponents will need to commence FEED to determine technical issues and cost parameters for development, hand in hand with a marketing campaign.
Demand for LNG is so strong it should not be difficult to sign up customers in Japan, South Korea, China, India and elsewhere.
As Oil Search business development manager Jesse Lee told last week’s petroleum seminar: “We are on the precipice of a monumental event – the development of LNG here in PNG.”
He said global demand was growing at a pheno-menal rate, rising from 40 million tonnes in 1985 to 143 million tonnes in 2005 and 158.6 million tonnes last year.
By 2015, annual demand was anticipated to hit 359 million tonnes.
During this period, Asian demand for LNG has become proportionally smaller, going from an estimated 64% in 1995 to around 48% by 2015.
Some marketing experts believe the current sellers market for LNG would last until around 2014, providing an excellent window of opportunity for PNG.
Esso Highlands managing director Gary Marony, in his talk on ExxonMobil’s role of “leading the way on LNG” said there was enough gas to meet global demand.
The big challenge was to transport “stranded gas” from remote locations such as the North
Slope of Alaska, West Africa, Australia’s North West Shelf and PNG.
He said seven LNG projects were started up last year and another seven this year with 18 likely to be completed in 2008 and 2009.
After 2010, ExxonMobil could be involved in Indonesia’s Natuna project, where the offshore gas field contains 70% carbon dioxide and 2% hydrogen sulphide; along with Scarborough and Greater Gorgon in Australia and the PNG project.
Until the button is pushed on the PNG development there will be some uncertainty, but InterOil’s president and chief executive Phil Mulacek said his group was fast tracking its development.
Mulacek said an engineering and procurement manager could be appointed within a month and the company would start site work four months into FEED with some long lead time equipment being ordered about two months after that.
Preparation is underway for drilling of Elk-4 and this will immediately be followed by Antelope-1 as InterOil tries to prove up adequate resources at its Elk discovery in Gulf province.
Britain’s highly fancied BG Group has pulled out of the race after unsuccessfully offering to purchase gas from other companies, including ExxonMobil and Santos, for a two-train LNG plant producing around 7.2 million tonnes a year.
The strong LNG demand has sidetracked the two big petrochemical projects by Japan’s Itochu and Mitsubishi Gas and the Indian Oswal Group because both are unable to bear the high feedstock prices obtainable from LNG.
The study launched this week by Oil Search and PNG Sustainable Development Program Ltd on a possible gas pipeline from P’yang to Daru, and an assessment of gas resources in Western province, could indicate the types of projects possible at Daru.
If there is adequate gas, a medium or small scale LNG plant may be feasible.
Otherwise, the economics would need to be assessed for Itochu and Mitsubishi’s methanol and dimethyl ethylene project and Oswal’s ammonia/urea plant.
Meanwhile, Rift Oil’s chief executive Jenni Lean is progressing a US$50 million exploration programme aimed at establishing reserves of 800 billion cubic feet at Douglas and other nearby prospects.
Success with this programme would support construction of a 900km gas pipeline to the coast and on to the huge alumina refineries at Gove in the Northern Territory owned by Alcan Australia.
Alcan is willing to sign a 20-year gas contract if these reserves could be proved up.
While much of the focus has been on oil and gas reserves in the Southern Highlands, new opportunities are opening up for discoveries that have been made in Western and Gulf province.