The controversy over the KGD6 block has come to a head and the
outcome will have a huge impact on downstream as well as the exploration
and production (E&P) space. Reserves estimates have been lowered
for the block.
June 2012 production was 30 million standard cubic metres per day (mmscmd), down from a high of 61 mmscmd. Reliance Industries (RIL) says production could dip to 20 mmscmd over the next two fiscals, due to technical difficulties.
RIL wants a market-linked price (roughly thrice the current price) for KGD6 gas once the current contract expires in April 2014. It also claims that, with the technical help of partner British Petroleum, and further expenditure, it could revive the block.
RIL also wants a large chunk of expenditure incurred over the past three fiscals to be written off. The government is unwilling to allow this. The government of India also says RIL hasn't fulfilled its drilling commitments. It is asking for a CAG audit of RIL's accounts. The production sharing contract (PSC) will have to be dissected and ambiguities cleared up so that this doesn't recur. Gas contributes about 10 per cent to the current Indian energy mix as well as being fertiliser feedstock. Over the next decade, gas' share in the energy mix could rise to 20-25 per cent. The power and fertiliser sectors generate roughly two-thirds of current gas demand. Demand from city gas distribution (CGD) networks servicing transport and domestic cooking needs is growing fast.
India's total gas consumption was about 56-57 billion cubic metres (bcm) in 2011-12. About 20 per cent of that was imported, with domestic production of 47-48 bcm. The fall in KGD6 production has meant a go-slow on pipeline infrastructure, and CGD development. The current policy offers sectors like power and fertiliser priority in supplies. Until KGD6 recovers, or other sources of domestic production are developed, CGD will be starved.
India will remain gas-deficient whatever happens. But it does have about 1,200 bcm worth of estimated reserves. At current production rates, that would be a reserve: production ratio of about 25 years. A coherent exploration policy would encourage more optimal E&P and reduce import dependence. Exploitation of other potential sources like coal-bed methane and shale gas have more extended time horizons but again, coherent policy making could speed things up.
Assuming KGD6 recovers and promising strikes like Gujarat State Petronet's Deen Dayal Field are developed, domestic production could hit 150 mmscmd by 2014-15. That would be significantly up from 2011-12 levels of 130 mmscmd. By then, demand will be about 230 mmscmd, implying nearly 80 mmscmd will be imported in 2014-15.
Imports will largely consist of LNG. Two LNG terminals in Hazira and Dahej are operational and terminals are under construction at Kochi and Dabhol. The ambitious 1,700 km TAPI pipeline from Turkmenistan via Afghanistan-Pakistan-India remains hostage to geopolitical complications.
Pricing policy will be a key factor in demand management. Gas has multiple benchmark prices. The Administered Pricing Mechanism (APM) price is currently $4.2 per mmbtu (million British thermal units) for producers like RIL and ONGC. RIL's demand is for a revised price of $12/mmbtu or more in 2014-15. Some Indian players have long-term LNG contracts with Qatar for $7. The TAPI pricing will supposedly be about $11.5 to $12.
Asian LNG spot pricing is linked to Japanese LNG rates. Japan is the world's largest LNG importer and demand there has grown since the Fukushima disaster. Japan's LNG pricing is a percentage of blended crude prices, known as the Japanese crude cocktail (JCC). Currently, JCC is above $16/ mmbtu. North America has lower gas prices due to shale extraction.
It's difficult for downstream industry to handle such volatility. Power, fertiliser and CGD have controlled tariffs and prices and cannot pass on sudden jumps in gas pricing. Bulk gas consumers will have to figure out how to stabilise gas costs to remain viable. Since energy is a politically sensitive issue, there will be a temptation to continue with APM. But if E&P activity is to be enhanced, policy must offer market-linked price incentives for new discoveries and production. Also, demand cannot develop in sustainable fashion unless prices are linked to market.
Demand for gas will grow, no question about that. But the government will have to display smart policy-making. Or else, gas will end up in a mess on the lines of diesel and kerosene. If all goes well, vast investment opportunities will open up. Pipelines, LNG terminals and CGD networks all have the potential to grow quickly along with E&P. Will the government learn a few lessons from KGD6? Valuations are low; any sensible policy movement could trigger a revival in stock prices.
June 2012 production was 30 million standard cubic metres per day (mmscmd), down from a high of 61 mmscmd. Reliance Industries (RIL) says production could dip to 20 mmscmd over the next two fiscals, due to technical difficulties.
RIL wants a market-linked price (roughly thrice the current price) for KGD6 gas once the current contract expires in April 2014. It also claims that, with the technical help of partner British Petroleum, and further expenditure, it could revive the block.
RIL also wants a large chunk of expenditure incurred over the past three fiscals to be written off. The government is unwilling to allow this. The government of India also says RIL hasn't fulfilled its drilling commitments. It is asking for a CAG audit of RIL's accounts. The production sharing contract (PSC) will have to be dissected and ambiguities cleared up so that this doesn't recur. Gas contributes about 10 per cent to the current Indian energy mix as well as being fertiliser feedstock. Over the next decade, gas' share in the energy mix could rise to 20-25 per cent. The power and fertiliser sectors generate roughly two-thirds of current gas demand. Demand from city gas distribution (CGD) networks servicing transport and domestic cooking needs is growing fast.
India's total gas consumption was about 56-57 billion cubic metres (bcm) in 2011-12. About 20 per cent of that was imported, with domestic production of 47-48 bcm. The fall in KGD6 production has meant a go-slow on pipeline infrastructure, and CGD development. The current policy offers sectors like power and fertiliser priority in supplies. Until KGD6 recovers, or other sources of domestic production are developed, CGD will be starved.
India will remain gas-deficient whatever happens. But it does have about 1,200 bcm worth of estimated reserves. At current production rates, that would be a reserve: production ratio of about 25 years. A coherent exploration policy would encourage more optimal E&P and reduce import dependence. Exploitation of other potential sources like coal-bed methane and shale gas have more extended time horizons but again, coherent policy making could speed things up.
Assuming KGD6 recovers and promising strikes like Gujarat State Petronet's Deen Dayal Field are developed, domestic production could hit 150 mmscmd by 2014-15. That would be significantly up from 2011-12 levels of 130 mmscmd. By then, demand will be about 230 mmscmd, implying nearly 80 mmscmd will be imported in 2014-15.
Imports will largely consist of LNG. Two LNG terminals in Hazira and Dahej are operational and terminals are under construction at Kochi and Dabhol. The ambitious 1,700 km TAPI pipeline from Turkmenistan via Afghanistan-Pakistan-India remains hostage to geopolitical complications.
Pricing policy will be a key factor in demand management. Gas has multiple benchmark prices. The Administered Pricing Mechanism (APM) price is currently $4.2 per mmbtu (million British thermal units) for producers like RIL and ONGC. RIL's demand is for a revised price of $12/mmbtu or more in 2014-15. Some Indian players have long-term LNG contracts with Qatar for $7. The TAPI pricing will supposedly be about $11.5 to $12.
Asian LNG spot pricing is linked to Japanese LNG rates. Japan is the world's largest LNG importer and demand there has grown since the Fukushima disaster. Japan's LNG pricing is a percentage of blended crude prices, known as the Japanese crude cocktail (JCC). Currently, JCC is above $16/ mmbtu. North America has lower gas prices due to shale extraction.
It's difficult for downstream industry to handle such volatility. Power, fertiliser and CGD have controlled tariffs and prices and cannot pass on sudden jumps in gas pricing. Bulk gas consumers will have to figure out how to stabilise gas costs to remain viable. Since energy is a politically sensitive issue, there will be a temptation to continue with APM. But if E&P activity is to be enhanced, policy must offer market-linked price incentives for new discoveries and production. Also, demand cannot develop in sustainable fashion unless prices are linked to market.
Demand for gas will grow, no question about that. But the government will have to display smart policy-making. Or else, gas will end up in a mess on the lines of diesel and kerosene. If all goes well, vast investment opportunities will open up. Pipelines, LNG terminals and CGD networks all have the potential to grow quickly along with E&P. Will the government learn a few lessons from KGD6? Valuations are low; any sensible policy movement could trigger a revival in stock prices.
No comments:
Post a Comment