Monday 7 April 2014

Is India offering the highest well-head price to gas producers?

Pratim Ranjan Bose
  
The query is innocent. But, it had hit the nail right on its head.
On April 4, the Supreme Court asked the Indian government to explain why they chose the “complex” Rangarajan formula for natural gas pricing that tried to establish a market price of natural gas in India by linking it a) with the netback price of imported LNG on long term contracts; b) the weighted average of prices at trading hubs like Henry Hub in the US and National Balancing Point (NBP) in the UK and the netback price at the sources of LNG supply for Japan.
C Rangarajan. Source: http://topnews.in

Netback is a theoretical approach to determine the true value of a commodity, minus cost associated with bringing it to the market place.
Apparently, the Rangarajan Committee resorted to such a complex theoretical exercise to strike the utopian balance between a regulated economy and an open market. The aim was to make gas exploration in difficult assets - as in the deepwater of Indian Ocean or Bay of Bengal – more attractive.
In the end, however, it proved to be a deadly toy in the hands of E&P companies to extract windfall gains.
In a controversial decision inJuly 2013, the Union cabinet decided to implement Rangarajan formula with effect from April 1, 2014.

Sharp increase in prices

The well-head natural gas prices are doubled from $4.2 to $8.4 for every million metric British thermal unit (over $ 6 per mmBtu in North Eastern states that enjoys special concession), to be revised on a quarterly basis.
Though the implementation is now postponed (by the Election Commission) till end General Election in May; the recent turmoil in Ukrain and firming up of gas prices in Europe, indicate Indian consumers may have to pay to the tune of $ 8.6 per mmbtu, once the prices are revised in June.

Costliest gas in the world?

To start with, unlike oil, gas markets are by nature regional. It is therefore impractical to link Indian price to either Henry Hub or National Balancing Point (NBP).
Moreover, prices are generally higher in Europe (than in the US) both due to its heavy usage in power generation vis-à-vis over dependence on Russian supplies. The regular increase in gas prices by Gazprom of Russia is a major stumbling block in improving relations between the two sides.
And, yet landed cost of Russian gas in Europe is lower than the price paid by an Indian consumer for domestic gas!

The Russian gas is delivered to Europe at approximately $ 9 per mmBtu. This includes the cost of transportation all the way from producing fields in Siberia. In other words the well-head price of Rusian gas must not exceed $ 6. It might be lower.
In comparison an Indian steel or ceramic producer located right on the well-head in Andhra Pradesh will now pay close to $ 9.5 per mmBtu or more ($ 8.4 well-head price + transportation) for Reliance KG-basin gas in the East coast.
Supplies to consumers in Gujarat or Maharashtra, on the West coast, will be costlier by approximately $ 2 per mmBtu, meaning that the final cost of the domestic gas is more or less same to  
Russia is no exception.
RasGas of Qatar delivers long term LNG to India ports at $ 12.5, including approximately $ 3 per mmBtu spent on liquefaction and sea freight. Exclude the trade margins and the cost of pipeline transportation from production field to sea-port terminal at Qatar, the well head price is much cheaper than $8.4 as enjoyed by Indian producers.
  The anomaly arises, because the pricing mechanism did not factor in the cost of producing the gas, so much so that the shallow-water D-6 gas of Reliance or GSPC is now priced higher than the deepwater gas produced in Brazil.
Source: http://vungtauoil.com/

Development of deep-water assets is considered costlier than the shallow water assets. And, development of an onshore asset is substantially cheaper than in the off-shore.
Ironically the Indian gas prices will not reflect this difference in cost structure.

Planned economy or market economy?

In an open economy price of gas is decided based on the cost of production and the market opportunities.
The new LNG coming out of Australia, for example, was priced exorbitantly high at $ 18 per mmBtu. This is partly to take advantage of the opportunities created after Fukushima disaster, in 2011.
But, Japan’s decision to take a re-open the nuclear power facilities and the scheduled Shale gas exports by the US beginning 2017; forced Australian producers to take a re-look at their pricing strategies. Last heard, Japan is renegotiating its contracts with Australia.
The point is open economy prices may move on both ways and consumers enjoy the liberty to plan its purchases.
Sadly, the Indian measure does not leave any such option before the consumers. Here the adopted methodology offers strong support to prices, making it apparently unidirectional.
And, the scores of Indian fertiliser or power generation facilities who planned investment at the prevailing gas price of $4.2 are now forced to take delivery of costlier gas through a “take or pay” clause.   
The Indian state of Tripura that has the largest onshore gas reserves in the country is the worst sufferer ofthis planned economy approach. To encourage E& P activities here, the government increased gas prices by nearly three times in the last decade. The price increase was applicable for both the existing and the new fields.
Source: www.decisionrisks.com

Considering the limited market opportunities (due to low industrial base of the state as well as inadequate pipeline logistics), the lead producer, the state-owned ONGC, is also allowed to tap value across the energy value chain - either by setting up a power station or fertiliser unit.
If that was not all, gas producers are now offered another hike in prices ($6 per mmBtu), eliminating the competitive advantage of this industrially backward border state.
The big question is: Could producers expect such super-normal returns, in Tripura, in an open market scenario where prices are a factor of demand and supply. Tripura is a test case. But the question may be valid for the country as a whole.
It might be worthwhile to ask, if the government introduced the new mechanism to give producers best of both worlds - the Open and closed market scenarios.

The unanswered questions

The Supreme Court has rightly asked why “simpler methods” like “cost-plus pricing” or “revenue-sharing” could not be considered for fixing price of natural gas.
In a different context through the question was raised early in the last decade, when Reliance Industries planned to sell a sizable chunk of its estimated daily production of 80 million standard cubic metre (mmscmd) from D-6 gas to a group power generation outfit at $2.8 per mmBtu.
The government objected to it on the ground that such a ‘low pricing’ would deprive India of its revenues.
Many felt the problem could have been solved by fixing a notional price of gas and claiming share of revenues on the same – the same principles as is applied in collecting taxes and duties in real estate – while leaving the rest of the decision making on the producer.
But the government had a different idea. They allocated the same gas at 50 per cent higher price at $ 4.2 per mmBtu. Reliance’s stock value soared in anticipation of higher profits.
The company started gas production in March 2010. Output soared upto 60 mmscmd in the following financial year. And, since then its only a downhill journey.
Source: http://02varvara.files.wordpress.com

D-6 is now producing only 13 mmscmd of gas. Consumers ended up wasting millions or billions of dollars in unutilised plant and machinery. But Reliance’s earnings are will be boosted by doubling of gas price to $ 8.4 per mmBtu.
Reliance is not the sole gainer of this pricing decision.
GSPC and ONGC too once shouted from the roof tops about the ‘rich finds’ they have struck in KG basin. None could establish their claims in reality, and will now find a shelter behind escalated gas price.
The proponents of gas price hike claim that it would boost domestic gas production in the long run. Time will tell, if they are correct.
For now, it helps a few.


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4 comments:

  1. Excellent article. One question I have. Does the age of discovered field have anything to do with price? I am asking this because if age of field is same for Russian example and kgd6 then there should be no price difference. But if they are different then is it fair to compare ? I have no idea how this works ...

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  2. An aged man spends more on medical expenses. An ageing field requires higher spend on per ton of oil/gas production. The high EOR expenses of ONGC in Bombay High is an example. But, there is another cost too. The cost of discovery, which is increasing as people are pushing the boundary and going into deeper water in search of hydrocarbon. That is why I took the Brazilian example.

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  3. Excellent piece. Is the Reliance block in D-6 in shallow waters or in deep-water?

    Regards,
    ranju

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    1. Dear Ranju, there is was a small mistake on my part in explaining. As per nomenclature D-6 discovery is deep water. Brazilian asset I mentioned is in ultra deep-water that attracts higher cost in developing. I referred D-6 'shallow' in comparison to Petrobras discovery. Error is regretted.

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