In late 2003, a multinational oil major offered to sell an Indian public sector power company liquefied natural gas (LNG) at $4.5-5 per million British thermal unit (mmbtu).
It was summarily turned down as an "overpriced" and "unviable" offer. Less than three years later, potential buyers from India -- including those who passed on the $4.5 offer -- are scrambling to buy LNG even at $7 or $8 per million British thermal units (mmbtu). It's a steal at that price: countries like Japan and South Korea are buying LNG at $11 and $20.
It's taken just three years to turn the market dynamics of the LNG industry on its head. With demand in India and China growing at 6-7 per cent a year, suddenly LNG is a suppliers' market.
But it's no party for suppliers, either. Between buying gas at respectable prices from producers across the world and India, to selling them to customers like power plants and fertiliser companies at a profit-generating rate, the suppliers have their work cut out.
"India missed the bus in early 2002-03 when supplies were available but Indian consumers couldn't understand the pulse of the market and refused to take a call," declares Nitin Shukla, CEO, Shell Hazira LNG, the Indian subsidiary of Shell Gas and Power. What are Indian LNG suppliers doing to ensure events remain in their favour?
Building on demand
First things first: this isn't a temporary situation. Natural gas is a clean fuel and given the rising costs of emission control equipment, Indian power generators are increasingly switching from coal-fired to gas-fired plants. As are auto makers.
Two months ago, India's largest car maker, Maruti Suzuki, launched a car with a factory-fitted LPG tank, the Wagon R Duo. Already, commercial passenger vehicles in New Delhi and Mumbai have switched to compressed natural gas. So demand for natural gas isn't going to taper off anytime soon.
Obviously, the demand is fuelling increases in the price of LNG. But there's another factor at work as well: the chronic gas shortages and the uncertainties related to international pipeline gas projects: both the Iran-Pakistan-India and the Myanmar-Bangladesh-India pipelines are still in the air.
A recent KPMG report on India's energy sector points out that in the long term, among the most lucrative areas for investment in the natural gas sector could be LNG facilities in areas where pipeline gas is not expected in the near future.
Some oil marketing companies have already taken that to heart. While ONGC is planning an LNG receiving terminal (where the gas will be imported and stored before being shipped out to customers) at its Mangalore complex, Indian Oil Corp has also announced its decision to set up an LNG terminal.
At Dabhol, NTPC and Gail, which own the power plant and the attached LNG facilities, are planning to sell the plant to an LNG operator such as Petronet LNG.
In turn, Petronet is considering doubling the plant's capacity from 5.1 mmtpa to 10 mmtpa, once it gets control of the facilities. It is also in talks with Qatar's Ras Gas to trade a stake in the Dabhol LNG facility in exchange for a long-term supply assurance.
The first task to cope with rising demand is to ensure supply. Globally, additional liquefaction capacity of 251 million tonnes per annum, or mmtpa (natural gas is measured in mmbtu when gaseous, and in mmtpa when in liquid form).
That's in addition to the existing 157 mmtpa, and will be in place by 2010. Of this, 145 mmtpa is being set up east of the Suez, in West Asia, South East Asia, Australia and Brunei.
This will facilitate the creation of 90 million tonnes in Qatar, Iran and Yemen, and 57 mmtpa in the Pacific region. Africa (mainly Nigeria, Algeria, Angola and Egypt) could also become a major source of LNG, adding another 64 mmtpa by 2010-14.
In India, too, while the facilities at Dahej are being expanded, new capacities are being set up at Kochi, Dabhol, Ennore and Mangalore (see chart). While Dabhol will be operational by 2007 and the Kochi terminal by 2008 or early 2009, the Ennore and Mangalore terminals are in the initial stages.
In the meantime, of course, there's always the import option. And given the increasing mobility of gas internationally, geography in sourcing fuel is not likely to be an issue.
"Liquefied gas can be transported from just about anywhere to anywhere, which will make it easier for countries like ours to source gas," explains Banmali Agrawala, chairman and managing director of Wartsila India, a Swedish gas turbine maker.
Last year India imported 5 million tonnes of LNG, mainly from Qatar under a long-term supply agreement with RasGas. Late last year and early this year, Shell Hazira imported spot cargoes of 4-5 million tonnes of LNG from Oman and Australia.
This year, Petronet LNG has also imported a spot cargo from Egypt and plans to import even more before the end of the year.
Definitions first. Natural gas is a fossil fuel occurring both by itself and along with crude oil. It is considered one of the cleanest fuels as it leaves no residue. Until the early 1980s, natural gas was burnt off when it was found along with petroleum (the flares that characterise oil rigs and installations).
But rapidly depleting oil reserves and continuously increasing demand for fossil fuels meant that natural gas began to be seen as a fuel in its own right. While compressed natural gas (CNG) is, as the name suggests, a compressed form of the gas, liquefied natural gas (LNG) is natural gas liquefied under pressure for easy transport.
Demand for natural gas in India is expected to grow three-fold over the next few years. By 2012, the demand for gas is expected to grow from the current 120 million standard cubic metre per day (mmscmd) to 400 mmscmd. This includes both CNG and LNG. Currently, gas constitutes only 9 per cent of the Indian energy basket but is expected to increase to 20 per cent by 2025.
One of the reasons for this growth is the growing number of gas-based power generation projects as well as the shift from diesel to CNG as
Currently, the power and fertiliser sectors consume around 75 per cent of the gas available in India, although demand from these sectors still remains unmet. Nearly 7,000 MW of power generation capacity in India is lying idle or underutilised for want of gas.
Some of this could change starting 2009-10, when the supply of gas is expected to increase as the Krishna-Godavari basin gas fields discovered by Reliance Industries and Gujarat State Petroleum Corporation (GSPC) will start production.
ONGC, along with its joint venture partners, is also stepping up efforts to increase production. The ministry of petroleum and natural gas is already negotiating with the governments of Pakistan and Iran to access the central Asian gas fields.
A feasibility study on the pipeline is underway at present. Within the country, too, the network of pipelines being put up by GAIL, Reliance Industries and GSPC is expected to be in place by 2009-10.
The price problem
Of course, price remains a critical issue in LNG supply and demand. The section above explained why demand for LNG isn't likely to come down anytime soon.
But it's also important to remember that Indian buyers have accepted the high-price regime in LNG mainly because it replaces naphtha, which is almost 60-70 per cent more expensive than even the spot LNG price.
"As long as this difference continues, LNG will remain the preferred fuel," says Shukla. Which is why companies that haven't tied up long-term supply deals (which would offer some measure of price stability) are still buying LNG in the spot market.
Since demand will remain high, it follows that LNG prices, too, aren't likely to fall. Analysts point out that crude prices are an integral part of the LNG price mechanism, so gas prices may continue fluctuating in the higher ranges along with crude oil prices.
Prosad Dasgupta, CMD, Petronet LNG, has a firmer prediction. "The Henry Hub price [the daily spot price at Henry Hub in the US] may be $4-5 per mmbtu by 2010," he says. (Present rates are $4-6, but were higher recently.)
But how high and for how long remain unanswered questions. How should LNG suppliers deal with the uncertainty regarding future prices and supply?
By entering into medium- or long-term supply contracts. Typically, long- and medium-term contracts are for 20 and 10 years, respectively (that's changing now, though, and long-term is coming to mean 10-12 years). But there are still advantages in these agreements.
While the supplier ties up customer for his supply, he also benefits from some certainty regarding revenue streams. For buyers in a volatile market, like the one prevailing, long-term contracts are favourable because they are assured supply at prices that are more or less fixed. Japan and South Korea, for instance, have entered into long-term contracts with their suppliers world-wide.
In India, Gujarat State Petroleum Corporation (GSPC), the state government-owned hydrocarbon company, for instance, proposes to have its own terminal in Gujarat and has zeroed in on Mundra in Kuchchh and Pipavav near Bhavnagar as possible destinations, and is seeking long term supply arrangements.
"We have started looking for long-term supplies available in the market," confirms Saurabh Patel, minister for power and petrochemicals, Gujarat state government. GSPC isn't alone. Shell, too, is in discussion with buyers in India for long-term agreements.
Meanwhile, it is also considering entering into a long-term supply contract with a liquefaction project in West Asia that would benefit its receiving facility at Hazira, Gujarat.
D J Pandian, managing director, GSPC, sums up the issue: "Long-term agreements are the only answer to supply and price uncertainties."
The Slippery Slope
If only it were as simple as matching demand and supply. But the LNG market is affected by factors that are beyond the control of buyers and sellers.
The cost-escalation in Australia's Gorgon project and Sakhalin Island in Russia strongly impacted natural gas futures and also LNG prices. It's gotten worse now, with the Russian government recently cancelling the licence of the Sakhalin II.
Huge question marks now hang over the availability of LNG from these projects in the long run. And the ripple effect is reaching out to affect medium- and short-term supply arrangements being negotiated currently by others world-wide.
In May this year, Chevron, the project operator and 50 per cent shareholder in the 10 mtpa Gorgon LNG development, revealed that the first LNG deliveries were likely to slip to 2011 from the original date of second half of 2010.
Although, industry observers believe a major escalation in construction costs is a big part of Gorgon's problems. Three years ago, the project was estimated at $11 billion, but rumours suggest that costs may be heading towards $15-18 billion, and will start operation only by early 2012.
The Gorgon news came on the heels of last year's announcements that costs in the Shell-operated Sakhalin II project had leapt from $11 billion to $20 billion, with a delay of nine months in first gas. The final blow came last fortnight when Russia's natural resources ministry declared that it had asked the country's oil and gas development agency to cancel Shell's environmental licence.
Russia's attempt to stop the development of its biggest gas project, the $20 billion Sakhalin II scheme in eastern Siberia, could be an attempt to tighten Kremlin's grip on the country's energy resources after the part re-nationalisation of oil company Yukos.
Industry observers suggest that a deal is being worked out between Shell, which owns 55 per cent of Sakhalin II, its partners Mitsui (25 per cent) and Mitsubishi (20 per cent), and the Russian government. The promoters may have to dilute their stake by 25 per cent in favour of Russia's Gazprom.