In line with the Rangarajan committee recommendations, the government is expected to mandate that all future oil contracts adopt a revenue-sharing model. What are the implications
For deepwater exploration, the revenue-sharing model will probably not work. Anybody coming in and investing billions of dollars will not wait for several years to recover his money. He would like to first recover his money and then share the profits. The tenth round of NELP will probably have a hybrid model of less risky ventures on revenue-sharing model and the risky ones like the deepwater blocks following the present cost recovery model. My perception is that where the investment is risky, people would want early cost recovery. If we want foreign companies to come in and bring in technologies and money, we have to give some concession.
Your subsidy burden is not going down despite the governments burden falling. Any complaints from the shareholders
There have been no shareholder complaints so far. The board has been showing concern time and again and we have taken up the matter with the highest authorities. I had even raised the issue before the Prime Minister and the finance minister. It is not that the gravity of the matter is not understood but the political compulsions are bearing heavily on everyone.
I recently returned from the US and investors there have shown concern over the issue. My take is that this is not sustainable any more. The fiscal deficit and CAD will go up if the current situation persists. This has ramifications of even our ratings coming down. Oil retailers have borrowed so much that it makes it difficult for them to borrow further. If you put any more load on companies like ONGC, our backs will break.
In first quarter, we got $40.17 per barrel as realisation while $40 is the cost of production, which gives little margins. Fortunately, we have other businesses so we are still in the black. But with these kind of profits we will not be able to generate enough internal resources. Our budgeted capex is R35,000 crore for this year. If we do not generate enough money we will have to dip into our own reserves, which could get finished in less than 2 years. After that what happens We have been going from pillar to post saying that we do not mind going to the market to borrow, but this would rather be for expansion than to borrow for our day-to-day business.
Do falling production numbers concern you
Our reserve accretion has been fantastic. Last year, we accreted 84.84 MThighest in the last 22 years. Our reserve accretion ratio was 1.84. We produced 46 MT and accreted 84 MT. But our fields are ageing. Around 75% of our production is coming from just 15 fields. This includes fields that started ONGC including Ankleshwar and Rudrasagar that were discovered in 1961. They are still producing. Also, Bombay High, which was discovered in 1974 and started production from 1976, is still producing. So, this is the kind of vintage we have. In the coming years, we expect production to pick up particularly with new gas fields coming into production on the east coast.
Our production is falling and we have taken a lot of efforts in putting IOR and EOR schemes. We have spent R33,000 crore, 16 schemes have been completed, 8 more schemes are running but we have seen that these fields are giving us production in the range of 7-8 MT of every year. Had we not implemented these schemes, the production would have been less by as much. The problem is that with every subsequent dose of investment that is coming in this IOR/EOR scheme, the production is falling. It is a case of diminishing returns.
In the first phase of the Mumbai redevelopment, we invested R8,000 crore and got 57 MT of oil and 16 bcm of gas. In the second phase, we invested R16,000 crore getting 36 MT of oil and 6 bcm of gas. In the third phase, which is on the drawing board, we may again end up spending R16,000 crore but the incremental production will be about 18-20 MT. We have requested the government for a differential tax rate for marginal and depleting fields.
Can you elaborate on the tax sops you have sought
The IOR/EOR schemes in the first phase cost us about $7 per barrel, while with the current schemes our costing is about $12 per barrel (in addition to the production cost of $40 per barrel). In the future, this would cost us even more. So if you see it in the context of net realisation we cannot take up any of these projects. We have requested the government for both the marginal and IOR/EOR fields to be taxed differently. If pricing is not be differentiated then at least taxation could be different. The statutory levies could be different, income tax or depreciation formula could be different. There are various models availablelike in Nigeria, the royalty is based on production. The slabs of royalty keep on increasing with production. In Russia, where they have tight oil or permeability is very less, they are taxed differently. In Malaysia, the UK, etc, they have given tax sops where the taxation rates are different and they are allowed to have faster depreciation, so you recover your capex faster.
What is the update on your KG basin block 98/2 that is set to be ONGCs first significant deepwater producing block
For 98/2, we are going to finish our appraisal by December, which is our deadline. We have already drilled four wells, and another four are being drilled. Two wells have shown very good gas reserves and one has given oil for the first time, that too in good quantity. The reserves might get upgraded too. We will submit our field development plan (FDP) next year, and if not in FY17, by FY18 we should be able to produce. The neighbouring G-4 field will contribute 9 mmscmd; the entire east coast has the potential to produce 35 mmscmd.
We have now signed an MoU with RIL for sharing its KG basin infrastructure. We want to use their facilities because their pipeline is just about one-and-a-half km away from where our field is. So, it makes immense sense for us to connect it to their fields as those facilities are lying under-utilised at the moment. We can use their pipeline, platform, etc, and bring it to Gadimoga. We have asked RIL whether these facilities will be available for the short-term till we are able to set up our facilities or can be available on a long-term basis. So, if it is for the long-term, we will not have to incur any capex.
What are your plans for shale gas, now that the policy has been approved by the CCEA
We have plans ready for 3 basinsKG, Cambay and Cauvery. The potential recoverable according to EIA stands at around 93 tcf in 3 basins. ONGC had made the estimation for 3 basins, which came to around 110 tcf. However, shale gas exploration will not be a panacea for all energy problems as land acquisition is going to become a very big problem as a result of the new land Bill. The number of wells that are required to be drilled for shale gas are more as compared to conventional gas because the productivity of wells is relatively less. It also requires 2-3 million gallons of water to be pumped per fracture, with an average of 20-30 fractures for every well. So, the costs of running the wells is high and the requirement of land, rigs, water, infrastructure to even evacuate this gas will be a challenge. American energy major ConocoPhillips is helping ONGC in its efforts to find shale gas.
Your subsidiary OVL is slowly getting larger than the parent. Is this a worrying trend
Every parent feels proud when his/her children grow. This is part of our evolution. Our perspective plan indicates that if OVL is contributing 15% today, it will contribute 45% by 2030 to the total kitty of production. So, the growth engine is OVL only. Why should we worry If it is doing well it is only due to the technical and financial support of the parent.
Is it disappointing that OVL has no presence in North America
We are conscious of our absence in North America. The reason is that we are working in many countries where US sanctions apply. One of them is Iran, and then there are Sudan, Syria, Libya, etc. Diplomatic efforts are on to see as to how we can move forward. But now, with the discussions happening between Iran and the West, things should look better, hopefully. Having said that, OVL is quite well-spread geographically with presence in Latin America, Africa, Russia and Central Asia.
Your term ends next February. How would you sum it up
I am not ready to hang up my boots yet. Ask me this question on February 28. All top officials in other oil and gas companies are from ONGC. When you go outside the PSU platform you have more freedom. Here, you learn about procedures and to work within the confines of government regulations. Today, we are producing 59% of countrys oil and 62% of its gas. India has 28 billion tonnes of reserves or prognosticated resources, of which 11 billion tonnes have so far been recovered with ONGC contributing 8.8 billion tonnes. Having said that, I have a lot of work to do before I call it a day.