India has potential to be a major gas importer
With brand new liquefied natural gas infrastructure and new pipelines opening, India has the potential to be a major gas importer. But the government faces a dilemma which may scupper its gas ambitions. Does it deliver much-needed market reform or does it protect millions of citizens living below the poverty line?
An impressive line-up of politicians took to the stage in New Delhi last month to tell the world that India is thirsty for natural gas imports.
For the first time ever, Prime Minister Manmohan Singh inaugurated the Asia Gas Partnership Summit (AGPS), as well as pressing the button to allow first flows through a new gas pipeline linking the Dahej liquefied natural gas (LNG) terminal on the west coast to factories 2,200 kilometres away in the northern states of Punjab and Himachal Pradesh.
But while calling on the country to use more gas to fuel India’s economic growth, Singh also said pricing reform was needed to encourage imports, increased domestic production and to bring Indian gas prices closer to international levels.
The power and fertiliser sector would also have to be weaned off cheap subsidised gas, with around 53% of India’s domestic gas production consumed by power generators and 26% by the fertiliser sector in the financial year 2010-11, according to government figures.
But these two sectors are also the most sensitive to pricing reforms, with 70% of the population working in the agricultural sector and the majority of the rural population without access to commercial energy. The prime minister acknowledged the difficulty of cutting subsidies and raising gas prices when millions of Indians still live below the poverty line. “The government has initiated gas pricing policy reforms to incentivise production of natural gas. We are conscious that remunerative energy prices are needed to ensure expanded energy supply,” Singh told delegates.
“At the same time, oil and gas are national resources and, therefore should be within a framework of governmental and regulatory oversight. The economic exploitation of these resources should lead to win-win solutions for both investors, as well as the people of India.”
But even without any pricing reforms of either gas, power, or fertiliser, India’s gas consumption is expected to rise by over a third in the next five years, according to forecasts by consultancy McKinsey. And even current levels of gas demand cannot be met by domestic supplies, highlighting the need for imports.
“India’s current demand of gas amounts to 160 million cubic metres a day (cm/d), of which 110m cm/d is met by domestic production. This implies a clear shortfall in the market,” Vipul Tuli, director of McKinsey India, told delegates.
With such a bullish outlook, India’s domestic gas production is not likely to meet climbing demand, with the government still developing the New Exploration Licensing Policy (Nelp) framework to entice global energy majors to invest, but in a way which also allows it to protect the country’s energy resources. So far, Nelp has led to a rise in domestic gas production, but not been as successful in attracting huge foreign investment as hoped.
And even assuming domestic production and transnational pipelines could add significant supply in the next five years – which is no certainty (see TAPI box) – India would still have to import LNG. And because India is price sensitive, gas demand could increase, depending on the international LNG prices.
Demand on the rise
In McKinsey’s base-case scenario – with no gas, power or fertiliser pricing reforms and assuming LNG prices over $14/m British thermal units (Btu) – gas demand is expected to reach 220m cm/d in 2017 compared with 163m cm/d in 2011. But if LNG imports were available at $8-10/m Btu, the level before last year’s Fukushima nuclear disaster, then demand could more than double to 340m cm/d.
This is because at over $14/m Btu, only fuel switching against oil products such as fuel oil or naphtha would be economically viable, potentially increasing demand by a maximum of 100m cm/d, according to McKinsey. At between $10-14/m Btu, power plants that supply peak demand and petrochemicals could switch to gas, adding an additional 80m cm/d on top.
If LNG was even cheaper then baseload power generation, fertiliser, and steel sectors could switch to gas at $6-10/m Btu. These last three industries could provide the largest boost to demand, increasing consumption by another 149.8m cm/d. But these sectors have preferential gas allocation from the government (in other words, subsidised domestically produced gas) so LNG is unlikely to compete unless imports become very cheap.
So India knows it will need LNG, with the Asian country expected to triple existing import capacity of 13.5m tonnes a year (t/y) to 40m t/y by 2015.
India’s major expansion plan includes upgrading two existing terminals (Petronet’s Dahej and Shell-Total’s joint-venture Hazira) as well as adding another four new terminals – Kochi, Ratnagiri, Ennore, and Mundra.
At the AGPS, the prime minister inaugurated Gail’s Dahej-Vijaipur-Dadri-Bawana-Nangal/Bhatinda pipeline, which directly connects LNG imports via the Dahej terminal to the gas-hungry north. The new pipeline has 66m cm/d capacity, which is enough to generate 3.5 gigwatts of electricity and provide feedstock for over 1.8m tonnes of fertiliser, according to Gail, the state-run energy firm. The project cost around 131bn rupees ($2.58bn) and runs nearly parallel to the existing 2,759 km Hazira-Vijaypur-Jagdishpur (HVJ) pipeline until Vijaypur before spurring off towards the north.
But India may not be able to compete with other Asian LNG buyers, who are currently paying around $16/m Btu for spot deals, because of state-set and subsidised Indian gas, power, and fertiliser prices. This means if India buys on the same level as Japanese and South Korean customers, it would increase its huge energy subsidy bill which the government forecast at $7.78bn for 2012-13.
“Indian LNG imports are very price sensitive. Everyone wants gas, but there is probably a $15/m Btu cap on prices we can pay,” one delegate said.
The only industries that can buy LNG are those that can pass on costs, such as petrochemicals or those switching to imported gas from expensive oil-products such as naphtha in fertiliser production, and they make up only a small proportion of India’s gas users.
India’s Petroleum Ministry statistics show the country imported 8.95m of LNG in financial year 2010-11, paying a total of 127.19bn rupees (which averages at $6.05/m Btu). LNG is imported on a combination of 55% long-term contracts and 45% on spot or short-term deals, but prices for both types of contract are set to rise in the short- to medium-term.
This is because the cost of long-term LNG contracts depend on the oil price – which is expected to stay high over the short term, while deals on the Asian spot LNG market pits India against Japan and South Korea, the two largest and highest-paying LNG buyers in the world.
India’s Petronet has a 7.5m t/y long-term supply deal with Qatar’s RasGas. It started as a 5m t/y deal set at a fixed price of $2.53/m Btu, but the terms of the contracts changed in 2009 when Petronet increased volumes to 7.5m t/y.
The new contract means the LNG price will be partly linked to the Japanese crude cocktail (JCC) price to varying degrees until January 2014, when it will be set at 12.65% slope. So if JCC on January 2014 is $100/barrel, the 12.65% slope would equate to an LNG prices of $12.65/m Btu.
The latest JCC price for February is 116.25/b, which would mean India pays $14.70/m Btu which is nearly on the same level as the highest price India paid for spot LNG, which was a little over $15/m Btu at the end of 2011 and way over the initial fixed price of $2.54/m Btu.
And JCC prices could rise even higher, with Japan depending more on oil and LNG to offset nuclear reactor outages after the earthquake and Fukushima meltdown last year.
In early April 2012, India also rejected a long-term Qatari deal for an additional 5m t/y, with a pricing formula based on a 14.5% slope to Brent crude prices, declaring it was too expensive. With Brent futures around $120/b, this would translate to $17.40/m Btu at time of loading at Qatar. Add on shipping costs, import duty, pipeline tariffs, and regasification, prices would reach over $20/m Btu.
India has also agreed other tentative long-term deals with potential US LNG exporters as well as Gazprom and BG Group expected to start in 2014 at the earliest.
In the short-term, spot prices are expected to rise with little new LNG production coming on line in the next two years, but demand to increase from Japan. Other Asian countries could also increase imports, with China and Thailand commissioning new LNG receiving terminals.
However, politicians are reluctant to raise gas, fertiliser or power prices – which would allow more LNG imports – because it would affect the rural poor the most. Despite government figures showing poverty levels dropping to 29.8% in 2009-2010 from 37.2% in 2004-2005, it still means around 360 million people live in poverty.
There is still scope for India to import LNG in the manufacturing of urea, a fertiliser chemical, by switching from naphtha to gas. Even at high LNG spot prices of $15/m Btu, this equates to $78/b of naphtha. This compares to around $119/b for Singapore naphtha, signalling a cost saving of a third.
Since the government subsidises fertiliser, to the tune of $13.1bn in 2011-12, it has been pushing for natural gas to be used for all urea manufacture to reduce the subsidy bill.
Becoming self sufficient would also save on subsidising imported urea, which sells internationally at $400/tonne, and is around four times higher than India’s state-set prices. Government figures show India produced 21.54m tonnes of urea in 2010-11 and imported 4.58m tonnes.
The deadline to convert all naphtha-based urea plants to gas was 2010, but this has been missed. An estimated 15% of India’s urea manufacturing plants still run on naphtha. And new urea plants or old facilities reopened and refitted to run on gas could also increase gas demand.
In the power sector, most of the installed generation capacity is state-owned and electricity prices are heavily subsidised specific to the end-user. Unlike fertilisers though, gas in the power sector is competing with coal (which is also subsidised), and coal is a cheaper fuel to burn to generate electricity.
But there are certain niche sectors that can use gas. This includes power plants that provide power during peak periods (and therefore can charge more) and captive generators which are dedicated to a single facility, such as a factory or steel mill.
Other factors which could result in India buying more LNG is faltering production from fields in the Krishna Godavari basin off the east coast, especially the D6 block fields.
From a peak of around 61m cm/d in March 2010, gas output from D6 fell to an all-time low of 28.2m cm/d at the beginning of March this year. D6 operator Reliance Industries blamed the production slump on technical issues, with six wells being shut in due to water/sand ingress. Flows are also well below the forecast 70m cm/d forecast in 2006.
In 2011, LNG traders signalled that declining production from D6 was the reason behind a surprise increase in India’s LNG spot buying, and that trend is likely to continue until output from the D6 fields stabilise.
Under Nelp, D6’s gas production is allocated to urea production, so India will have to weigh up whether importing LNG or importing urea will have a larger impact on its subsidy bill.
Other potential production from the Krishna Godavari basin includes Oil and Natural Gas Corporation’s (ONGC) ultra-deep water UD-1 gas discovery in block KG-DWN-98/2. The Indian state-owned energy firm plans to invest $2.89bn in developing the find by 2016-17. UD-1, which holds about 111bn cm of gas, according to local press reports, could produce up to 20m cm/d for 14-15 years.
Predicting the future of India’s domestic gas production is difficult. Many of the country’s sedimentary basins remain unexplored.
In the short term, India will need LNG imports to meet its domestic demand. While gas still makes up a small part of India’s primary energy mix, around 10% compared to a global average of around 25%, there is huge potential for more gas consumption as the government tries to diversify energy sources.
And while there is a need for pricing reform, politicians have to tread carefully around energy and fertiliser policy to avoid harming the poorest members of society. In his book, Natural Gas in India: Liberalisation and Policy, Anil Jain argues that the Indian government must encourage private investment in the gas sector by providing the right price signals. Supply must be able to meet demand at reasonable prices but this does not mean a “bonfire of all controls or the complete abandonment of economic planning.”
“Not all these reforms involve the greater reliance on prices and markets. Nor does the needed reform programme entail abandoning objectives such as subsidising important items of consumption for the poor (fertiliser and power),” says Jain, a senior visiting research fellow at the Oxford Institute for Energy Studies.
Despite huge growth in Indian gross domestic product (GDP) to $1.73 trillion in 2010 compared with $460.2bn in 2000, and similar increases in energy consumption, prices have not risen to the same extent.
And those price controls aimed at protecting the poor, may now be holding back efficient exploitation of India’s gas sector and draining public funds in expensive subsidies for imported gas and fertliser.
India has to find a way to loosen gas policy in a way that allows both economic and social growth.
Gas prices: two systems, one country
There are two gas-pricing mechanisms in India: the Administered Pricing Mechanism (APM) and the regime included in the New Exploration Licensing Policy (Nelp). The price of imported liquefied natural gas (LNG) is not state-set and depends on bilateral contract negotiations and the international spot market.
Implemented in 1987, the APM was the government’s attempt to encourage production from state-chosen nominated gas fields and undeveloped fields, via the Discovered Fields Exploration Policy (DFEP). Under DFEP, private companies, working with India’s state-run firms, negotiated prices through production sharing contracts for undeveloped fields. Once on stream, the gas is sold via state-owned company Gail at APM prices.
Prices for APM and DFEP gas are set by the government via the state-run firms or by a fixed formula agreed by private companies in joint ventures. It is the main pricing regime for selling gas to the power and fertiliser sectors.
Although there were notable APM gas increases in 1992, 1997, and 2005, prices stayed below production cost, so state-owned companies, mainly India’s Oil and Natural Gas Corporation (ONGC), had to bear the difference. But because the state-owned companies were making money in other business, these subsidies are not regarded as losses but “under-recoveries”.
But in May 2010, APM gas more than doubled to $4.20/m British thermal units (Btu) from $1.80/m Btu, bringing gas prices closer to the true cost of production. The rise also reduced some of the price distortion, bringing APM more in line with gas produced under the Nelp pricing mechanism.
Nelp was introduced in 1998, and aimed to encourage exploration and production. Pricing for gas produced from fields developed under the Nelp regime is still evolving, but it is expected that gas priced under the policy will overtake APM and therefore make it the most relevant pricing mechanism.
Nelp helped see domestic gas production almost double over the last decade to 52.34bn cm/y in 2010, Cedigaz data showed. Gas produced under Nelp allows gas producers to “discover” the price of gas themselves. But they are still required to get its “value” from the government which is reviewed every five years.
Nelp states that the “discovered price” should not be lower that the “government-determined value”, which means the government effectively sets a floor on gas prices, and therefore protects the state’s royalty and profit margins (see Nelp guidelines below). This has resulted in gas being sold at multiple prices.
However, Nelp has inconsistencies which could explain why foreign firms have not invested heavily in India’s gas upstream. For example, while Nelp gives producers marketing freedom to sell gas domestically, the government is also allowed to allocate gas according to its gas utilisation policy.
During the first decade of Nelp’s implementation, the government did not exercise its right to allocate gas. However, it did for Reliance Industries’ D6 block, in the Krishna Godavari basin, with output prioritised to urea manufacturers first, followed by liquefied petroleum gas (LPG) production plants.
Smoking the TAPI peace pipe
Delegates to the Asia Gas Partnership Summit in New Delhi broke into applause after Pakistan confirmed its commitment to the Turkmenistan-Afghanistan-Pakistan-India (TAPI) gas pipeline.
“I very proudly join my hands with the Indian, Afghanistan, and Turkmenistan governments in the TAPI project,” Ministry of Petroleum and Natural Resources secretary Muhammad Ejaz Chaudhry, told delegates. “Let’s not fight. Let’s integrate, let’s cooperate.”
He added that construction could start in eight to 10 months time. The pipeline could be complete within two-and-a-half years, with first gas in 2016. Chaudhry also said Pakistan’s natural-gas fields were depleting, and TAPI supply would offset a fall in domestic output.
Rune Stroem, director of energy at the Asian Development Bank (ADB), later told the summit more progress had been made with TAPI in the last two years than the previous 15 years, adding an inter-governmental agreement for the 1,800km pipeline was signed in 2010.
He said that inflation had increased the pipeline’s estimated cost to $10bn, up from the $7.6bn costing given in 2008. TAPI will transport between 60-90m cubic metres a day (cm/d) of gas from Turkmenistan’s South Iolotan-Osman field in Turkmenistan through Afghanistan and Pakistan to India.
Stroem said Turkmen Gas, Afghan Gas, Pakistan’s Inter State Gas System (ISGS), and India’s Gail were discussing sales-purchase agreements. “They’re coming to a conclusion and there have been very positive responses by the four parties,” he added. The ADB is the co-ordinator for TAPI and funded a feasibility study for the pipeline in 2004.
The Indian government, keen to increase gas’s share of the country’s energy mix, also welcomed the chance to import gas via pipeline. “We will pursue gas wherever it exists in the world, through such projects such as the proposed TAPI pipeline project,” R P N Singh, Union Minister of State for Petroleum and Natural Gas, said.
The gas could also be delivered for $10/m Btu, according to consultancy McKinsey’s, which is cheaper than LNG, but more expensive than domestically produced gas.
But despite the optimism, some delegates were sceptical because of the lack of security in Afghanistan and parts of Pakistan. Oil and gas infrastructure is often targeted by terrorist groups in the Middle East and Africa.
“TAPI has US backing over IPI (Iran-Pakistan-India) but it’s hard to see happening,” one diplomatic source told Petroleum Economist. The source added that Afghanistan may use TAPI as leverage to get more funding to improve security, but it would not necessarily mean the pipeline would be adequately protected.
Stroem agreed that security was the major challenge. It would be in each country’s best interest to protect the pipeline to earn transit fees, but the relevant government may lack the resources. He added that other major hurdles included attracting project sponsor and financing for the risky project.
Delegates also said the IPI project has been off the table since the Mumbai terror attacks in 2008 when Islamist gunmen from Pakistan killed over 100 people in the Indian city. At the time of the attack, India was already under pressure not to go ahead with the IPI, with objections led by the US because of ongoing tensions with Iran.
In 2008, India and the US also signed a nuclear energy deal to allow the Asian country access to technology and nuclear fuel for civilian use, sealing the fate of IPI.
The Myanmar-Bangladesh-India pipeline has also failed to materialise after Myanmar instead signed a deal with China, leaving India with limited options in terms of pipeline gas imports.
Figure 1: India's oil and gas infrastructure