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'Our gas price is fair, our costs are competitive'
RIL Director PMS Prasad addresses the many charges laid at the company’s door - NTPC mulls doubling power generation capacity - NTPC sets Rs 17,700 cr capex - NTPC warned against commenting on sub judice matters - PowerMin asks NTPC to sign contract with RIL - PowerMin asks NTPC to sign gas contract with RIL: sources">PowerMin asks NTPC to sign gas contract with RIL: sources - RIL cautions NTPC on commenting on sub-judice matters Reliance Industries’ gas field off India’s east cost has been a subject of massive controversy for several months, with allegations of costs being inflated, and the government thereby being denied its fair share of revenue. There are allegations of price gouging, and of Reliance reneging on lower price contracts. There are charges that so-called independent experts are not independent, and that a friendly minister is favouring the company. Some of the issues are in court, others are not. The litigants are Reliance Industries Ltd (RIL), managed by Mukesh Ambani, Reliance Natural Resources Ltd (managed by Anil Ambani) and the government-owned National Thermal Power Corporation (NTPC). Other than speaking through court documents, Reliance Industries has so far maintained a studied silence on most of the issues raised. Now, for the first time, a senior Reliance official has spoken to a newspaper, and addressed the key points of the controversy. In an extended interview that lasted more than two hours, PMS Prasad, who has headed RIL’s petroleum business for many years and who recently joined the company’s board, defends the company’s position and seeks to put the controversies to rest, while steering clear of all matters that he felt were sub judice. Prasad contends that the gas price of $4.20 per million British thermal unit is fair, and in any case lower than what is being paid by companies in other deals. He also argues that Reliance’s capital cost for developing the D6 gas field compares very favourably with other such fields. He says Reliance offered a fair deal to NTPC which, however, did not accept it and went to court; he feels NTPC is the loser, because it is buying more expensive gas from elsewhere. He also denies the charge that Reliance has stalled any audit of its costs by the Comptroller and Auditor General, arguing that there was no contact with CAG till April this year. Prasad feels Reliance has not got the credit it deserves for having improved the country’s energy security by producing so much gas, in such quick time, from a field where others have failed to find gas. Excerpts from the interview: Please respond to the charge that a gas price of $4.20 per million British thermal units (mBtu) is high, since current gas prices are at a seven-year low. There is always a difference between contract and spot prices. Contract prices were still in $6-7 range, when spot prices went through the roof. We all know that spot LNG (liquefied natural gas) was coming to India in the $22-25 range, and we know of some deals which were done at spot prices of $27. Some contract prices are linked to the price of oil, but there too the indexation is not 100 per cent. When this price of $4.20 was approved, spot prices were much higher at $6-8. I don’t think these comparisons (with today’s spot prices) are fair. I genuinely believe the $4.20 price, compared to other gas prices in India on spot or contract LNG price coming to India, is very competitive. Your capital expenditure for developing the D6 field started at $2.5 billion, then became $5 billion and then $8.8 billion. This has led to charges of gold-plating and denial of revenue to the government. How do you explain such sharp increases in capital cost? In October 2002, we announced the gas discovery and in September-October 2003, because we put in the bid to supply gas to NTPC, we wanted to see if we could develop the field as quickly as possible. We put together some concepts at the prices that were prevailing, and it would cost about $2.5 billion for initial development. We continued to drill more wells, and do geotechnical investigations. We now knew that the reserves had gone up from the original 5 trillion cubic feet (tcf) of gas reserves that we thought were there, to 10-11 tcf. So we had to rework the original concepts. Also in 2005, we had the tsunami, so we had to do tsunami-proofing. Prices, too, had gone up. I’ll give you an example. In 2003, we were using the rig that helped us to discover this field, and the cost we were paying was about $110,000-115,000 per day. Add the service and it was of the order of $225,000-$250,000. For the same rig today, I am paying close to $800,000 a day. The rig that we hired in 2005 and 2006, we are paying over a million dollars. That explains the increase. We were at the peak of the commodity cycle between 2006 and 2008. Most of our commitments were made in 2006. That is the time we went to the director-general of hydrocarbons, to say that we have bigger gas reserves here. The government said you go and produce more. So we scaled up our production plan from 40 mscmd to 80 mscmd (million standard cubic metres per day). Meanwhile, with higher crude and gas prices, everybody in the industry was investing. What otherwise was a marginal field suddenly became a viable field. But service capacity did not go up proportionately, so there was a lot of pressure on the cost of these services. That’s how our cost went up to $5.5 billion. That was for the initial investment. When we went with the revised development plan, we did not project the cost over the life of the field, because we already had the bad experience of having estimated a cost in 2003 prices, and then revising it at 2006 prices. But the government wanted to see what will be the cost through the full life of the field, and we were asked to cost the whole thing. That is how the figure of $8.8 billion came. There is a misconception that we have spent $8.8 billion; we have not spent it. It is the money that we will be spending over the life of the field. At $8.8 billion, what is the capital cost per unit of gas? And how does it compare internationally? If you take 11 tcf as the reserves, it converts to 1.8 billion barrels of oil equivalent. I will spend $8.8 billion, plus the $700 million spent initially on exploration and appraisal. The total will be $9.5 billion, which works out to a little over $5 per barrel of oil equivalent. The international benchmarks are $6-9 for comparable fields. I cannot compare our cost to anything here in India, since ONGC is yet to produce from the KG basin. Internationally, you have three ways of comparison. You can compare it to the CERA (Cambridge Energy Research Associates) cost. Then there is Goldman Sachs and another investment bank; they do cost comparisons every year in terms of reserves and development and production costs. The third is what has been announced for an international company’s project. Using these three methodologies, I think we compare very favourably. Goldman Sachs’ benchmarking tells us that in the deepwater regime, we are among the lowest, in terms of capital cost in dollars per barrel of oil equivalent. This is also the fastest discovery and development of a field, especially when there are no support services nearby, everything has to come from Singapore or Dubai. We are among the best among comparable fields, in terms of both cost and time. It is said that the prices of services and rigs have fallen now. Yes, some prices have come down but not for deepwater services, which is what we need. Deepwater rig prices are exactly the same as they were in 2008, when they were at their peak. Maybe there has been a slight softening. When ONGC opened a bid for a deepwater rig in April or May, they had only two offers and one of the offers was based on the rig we were using, because that contract will be running out in one or one-and-a-half years. If you look at what is called the effective cost per day, it is $560,000-630,000. If we include associated services, it goes to over $1 million today. We are spending a million dollars a day because most of our equipment, commodity, services and deepwater installations were contracted in 2006, when the market was at its peak. Today, the market may have come off a little but only in some senses, like jack-up rigs have fallen. But we do not use jack-up rigs or shallow water floaters. We are unfortunately drilling 1,000-1,500 metres, so we need ultra-deepwater rigs. Some of our wel ls, which we will be drilling soon, will be at 3,000 metre. If you want to get a good price, you have to contract for a long period of, say, two, three or five years. Contractors don’t want to give a rig for a short period. Ultimately, there are only a few players in the deepwater drilling business. The BPs and the Exxons and everybody did the same thing. They signed five-, seven- or 10-year contracts at high prices. But the market did not come off. Quite a few deepwater rigs were being built but, in this economic crisis, all finances had gone and all rig construction has stopped. So in reality the rigs that were to be built are not there, and the market is still strong. The second thing is Petrobras, with their big discovery off the coast of Brazil, requires some 38 rigs for exploring and developing fields. So, big demand is anticipated, and the market remains firm. Today, if you see the earnings of most of the exploration and production companies, they are not great because they are still paying high costs, while the prices of oil and gas are not great. If you are so confident about your costs, why have you stalled for two years the audit of your costs by the CAG (Comptroller and Auditor General)? I am very surprised to hear this. We have had only one interaction with CAG — that was in April-May this year, when there was a meeting in the ministry toPages: [1] 2 3