Oman's gas development policy

15 October 2001

Undersecretary at Oman's Oil & Gas Ministry Salim bin Mohammed bin Shabaan al-Ojaily* spelt out the sultanate's gas policy at MEED's Opportunities in Oman conference in London on 19 September. The following is the full text of his presentation

Oman is a relatively new player in the gas industry and a moderate oil producer which has for many years depended mainly on oil for its mainstream revenues. Oil reserves are limited and much smaller than those in other Middle East countries.

It is not too difficult to see that the need for Oman to diversify the economy from high oil dependency is paramount. In these circumstances, gas discoveries, made in the 1990s whilst drilling for oil, could not have come at a more opportune time. The government initiated studies which indicated that reserves were far in excess of our domestic requirements. This was the beginning of our aspiration to create a gas industry to monetise the gas reserves and provide infrastructure that would promote jobs, mainly for Omanis.

Oman's Vision 2020, launched in 1996, is to use gas to help develop new industries that could introduce new technology, new skills and help create high value jobs. Since then, further significant discoveries have been made and our proven reserves at the end of 2000 were 21 trillion cubic feet (tcf) with the expectation that reserves are in excess of 30 tcf. Recently announced discoveries increased reserves by some 10 tcf.

To succeed in creating a gas industry, we have looked at gas development programmes elsewhere and grouped them into three categories:

Trinidad & Tobago's main challenge was high unemployment.

Indonesia's priority was to generate foreign earnings first to support liquefied natural gas (LNG) exports followed by converting gas into chemicals

Pakistan's priority was to develop domestic gas use without exports.

The approaches adopted by Trinidad & Tobago and by Indonesia appeared to have met with success. Against this background, Oman decided to develop gas initially to support LNG exports.

The LNG business is very capital intensive. It is hard to enter and even harder to leave. It is in all respects the classic commodity business. Traditionally, it has achieved high plant and shipping utilisation.

A number of things will change in the future. First, gas demand is growing due to rising power generation consumption and the desire to reduce harmful emissions. Since its inception 30 years ago, demand for LNG has grown by 7 per cent a year and this rate of growth is continuing. The traditional markets of Japan, Korea and Taiwan still account for more than 70 per cent of demand, but growth is highest in Europe and the USA. I believe this rate of growth will continue, but growth over the next 10 years will come mainly from new markets.

The global spread of the industry will continue with new markets emerging in India, China, Central and South America. New suppliers will emerge in Africa, Russia, Norway and the Middle East.

Shipping routes will become more complex. LNG shipping 25 years ago was confined to some simple A to B routes between separate supplier and consumer pairings. Now, there are many examples of LNG ships passing empty on return voyages. The scope for improved efficiency of usage of these expensive assets is clear. Swap deals are already being seen in the industry, and these will continue and grow in importance.

The other major change is that a significant amount of demand is being met by expansion or debottlenecking of existing assets. A new greenfield LNG development will cost $4,000 million-8,000 million for a worldscale supply chain. Increasing the size of such a facility by 30-50 per cent can cost as little as 10 per cent of this amount. As the industry matures, it will get harder to get greenfield projects off the drawing board.

On the consumer side, there is deregulation in a number of mature LNG markets such as Japan, Korea and Spain. Our experience is deregulation stimulates demand growth. We are seeing seasonal variations in gas demand in many markets. If this trend continues, we will see inevitable price differentials for our product between winter and summer.

In traditional markets, we see increasing uncertainty caused by deregulation leading to demand for shorter-term and more flexible contracts. We also expect more extreme seasonal swings and an increase in spot trading in the winter. Demand growth will require major capital investments but this should be addressed in debottlenecking or extended terms to existing contracts.

Emerging markets such as China, India and South America will require major capital investments against a backdrop of generally poor bankability. They will still require conventional long-term, 100 per cent take-or-pay contracts and provide the most natural fit for new greenfield developments.

The US market will grow significantly as an LNG outlet over the coming 10 years, but will remain a pipeline-dominated market. For Middle East producers, the US is always likely to be a marginal market, one where money can be made sometimes, but not always.

The consequences for Far East and Southern European markets will be new contracts with shorter duration and more flexibility in annual contract quantities. Many will offer more seasonal offtake flexibility. Deregulation will lead to sellers paying more attention to the wording and consequences of take-or-pay clauses. If the buyer has no tangible assets and no track record in the industry, sellers will be far more interested in how they can secure their income.

What will probably not change much is price. Gas will remain a premium fuel. Steady demand growth will continue to hold prices up.

In emerging markets, new contracts will continue to look similar to those we have come to know over the last 25 years. Prices are likely to be similar to those in traditional markets.

I believe the long-term looks bright for gas suppliers. We will see more complex shipping arrangements to maximise use of the LNG fleet. We will see a trend towards shorter-term contracts and genuine spot sales of LNG.

So how is Oman prepared to meet the challenges? The location of gas reserves allowed the development of a plan to extend the existing gas pipeline network and to link the pipelines to the industrial and coastal towns of Sohar, Sur and Salalah. At each of these locations, gas is to be used to drive development of a local industrial park, each with one or more major gas-based industries supported by light industry and commerce.

The first major component of this grand scheme was Oman LNG. Feasibility studies were completed in 1994, work started in late 1996, gas sale agreements were reached with Osaka Gas of Japan and Dabhol Power in India in 1997 and 1998 and the first gas and condensate was produced in 1999. The first LNG was delivered exactly on schedule on 7 April 2000 into the Korea Gas Corporation (Kogas) vessel, Hanjin Sur. Financial completion was on schedule in May 2001.

The downstream facilities cost $2,200 million. Each LNG ship to transport the gas to Korea cost $200 million. The total cost of the supply chain was about $6,000 million. Much was raised on international markets. In the case of the Oman LNG plant itself, 80 per cent was in debt and 20 per cent in equity. An initial facility of $2,000 million was raised in the markets. The plant cost $1,800 million and the maximum debt used was $1,350 million.

We have delivered more than 70 cargoes of LNG to Korea, Japan, Spain and the US. Some 60 per cent of staff are Omani. The underspend has already allowed us to repay significant tranches of equity, and current high gas prices will allow us to pay dividends to our shareholders that will ensure that by early 2002 they will have received their initial investment in full. In addition, of course, our lenders are already receiving payments and interest on the loans.

The LNG project alone will contribute some 8-10 per cent to gross domestic product (GDP). A substantial number of jobs have been indirectly created. It has contributed to the cost of a new 200-bed community hospital and major improvements to local road infrastructure.

The LNG project is merely the first step in a much wider strategy. The government has already placed contracts for the construction of two other main gas distribution lines that will complete the basic gas distribution infrastructure. These will be operational by the end of 2002.

The government with private sector partners is working on other projects including:

the expansion of Oman LNG by the addition of a third and, possibly, fourth train. The cost is $600 million-700 million per train. Completion target for the third train is 2005

an aluminium smelter in Sohar with target completion date of 2004

a second oil refinery, based in Sohar, primarily designed to convert residual products to distillates. An associated polypropylene unit is being studied. Completion is expected from 2004 onwards

two urea fertiliser plants, one in Sohar and one in Sur. These are timed for 2003 onwards

methanol production facilities in Sohar planned for early 2004.

Total gas industry investment of $8,000 million is expected over the coming 10 years.

Salim bin Mohammed bin Shabaan al-Ojaily is also vice-chairman of Oman Gas Company and chairman of Oman LNG

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