Mar 092012

In spite of advanced technology, reservoir uncertainties are part and parcel of the industry. P. M. S. PRASAD, EXECUTIVE DIRECTOR, RELIANCE INDUSTRIES LTD While the Government’s loss is only lower profits, the contractor stands to lose his investment.

Be it gas pricing or falling output from the country’s largest gas fields, Mr P. M. S. Prasad, Executive Director, Reliance Industries Ltd, is held responsible for all. Once a backroom boy of Mukesh Ambani’s petroleum business, today he is the most sought-after man in the sector.

Reliance has come in for severe criticism for not being able to check falling output from the producing fields in D6 block since it hit a peak of 60 mmscmd in the end of 2009. The output is expected to further drop to 27.60 mmscmd in 2012-13 (D1 and D3 fields to produce 20.20 mmscmd, and MA fields 7.40 mmscmd).

In an interview with Business Line, Mr Prasad says that RIL takes pride in building this mega-size, complex deepwater project that put India on the global deepwater map, besides, the huge economic multiplier effect of delivering 1.8 trillion cubic feet of gas to the Indian market, which translates into savings of $27 billion of wealth transfer by way of crude imports saved, or $14 billion in terms of liquefied natural gas imports saved.

Questions are being raised on the basis of RIL revising the field development plan. Did your geologists go wrong in assessment of data?

Oil and gas is a business where one has to perpetually live with probability and uncertainty. Massive investments are required in terms of both time and money associated with gathering of geological data and information. Following these, a development plan is formulated, which naturally has to be made on the basis of data/information available at that time.

The KG D6 deep water reservoirs were the first to be developed in India. No experience or analogy existed to predict and model the behaviour and performance of these entirely new plays in hitherto unknown areas. How then does one arrive at points of reference and calibrate forecasts?

Nevertheless, we pioneered in the use of frontline technologies, and then made sure that the reservoir models were reviewed and validated by various global experts. Only then did we venture into formulation of the development plans.

So what went wrong…?

The Initial Development Plan (IDP) was submitted in early 2004. By that time, besides seismic surveys through the entire block, RIL had drilled 4 exploratory wells. This is the data on which we based our initial model, and had it validated by the best global experts before formulating the IDP.

The IDP having been approved, we sought permission for laying the transportation pipeline to evacuate gas, which (permission) only came in early 2006. RIL didn’t sit idle.

We continued with technical assessment, analysis, and engineering efforts. These led to another 9 discoveries in the block. Further drilling and extensive coring (280 m) in two development wells, the acquisition of additional 3D Seismic acquisition and extensive studies led to the upgradation of the resource base. This compelled us to optimise the development plan with commensurate increase in capacity and facilities vis-à-vis the IDP. Again, the estimates of reserves were reviewed and validated by the best global experts. Based on the available data and expert reports, the block Management Committee approved the AIDP (amended initial development plan).

It was only during production, that actual reservoir behaviour was seen to be deviating from earlier predictions. In spite of the most advanced technology during the last two decades, especially in earth sciences, reservoir uncertainties and surprises are part and parcel of the industry. More so on the East Coast, where there were no prior reference points to calibrate the predictions.

Usually, international companies of repute are involved in reserve estimations. Who did the estimation for the two — D1 and D3 — producing fields for D6 block?

No sensible company invests huge sums of money without going through a process of validation. In this case too, prior to submission of the development plan, reserves and production estimates were reviewed and validated by several internationally-reputed experts/consulting companies who had done similar work for other major oil companies.

How does RIL justify such a steep rise in cost? (AIDP cost increased to $ 8.83 billion from $ 2.47 billion for IDP).

You are comparing apples with oranges. So, not only did the capacity and the facilities undergo a change, but the IDP estimates were based on September 2003 prices. The period from October 2003 to the third quarter 2006 saw an unprecedented demand surge for oil field equipment and services fuelled by rising oil prices.

An unprecedented demand explosion across the supply chain occurred as higher returns drove the increase in global E&P spend. This led to stretched vendor capacity in sub-sea hardware and installations; acute shortage in availability of raw materials, manufacturing capacity and rigs — leading to cost escalations of up to three times.

The sharp increase in global prices of supplies and services, limited availability of vendors for hi-tech deep water operations, and change in the scope of the development plan led to the increase in cost estimates. Projects executed by global oil majors during this period faced significant cost escalations, anywhere between 100 to 200 per cent, and significant project delays.

People say that rise in development cost benefits RIL, as the depressed Investment Multiple (IM) gives lower share of profit petroleum to the Government. Do you agree?

The argument is devoid of all economic logic, and exhibits complete ignorance of cost recovery method as it operates in the production-sharing contract (PSC). In fact, it is the contractor who is most adversely affected when the project costs increases. The contractor spends his own risk money (but not the Government’s) on exploration & development.

The costs, when recovered, are of actual expenditure on goods and services procured paid to vendors and service providers — all on an arm’s-length basis. At no stage, in spite of multiple audits, has there ever been even the slightest suggestion that the contractor has claimed any unsubstantiated expenditure as cost recovery.

How does the cost recovery mechanism work in the production-sharing contract?

As far as cost recovery mechanism under the contract is concerned, when costs are eventually recovered, often after ten years, the cost of capital/interest isn’t included as per the production-sharing contract. The only way, therefore, to recover the real value of the investment is by reaching a higher investment multiple in the shortest possible time. The risks the contractor faces include higher-than-anticipated costs, lower production, and sub-market gas prices.

However, the Government earns both profit petroleum, royalty and taxes from the first day of production, without having invested any money or taken any risks. Therefore, while the Government’s loss is only lower profits, the contractor stands to lose his investment.

Can you illustrate the point?

Since total revenue is a product of recoverable reserve which is finite, and gas price which is market-based, let’s assume the contractor gets a total revenue of $100 by way of gas sales, and his cost is $40, which is recoverable. The profit of $60 ($100-$ 40) is shared between the Government and the contractor. Assuming a share of 30 per cent for the Government, and 70 per cent for the contractor, the Government would get $18 and the contractor $42. Suppose, the cost increases to $80, then $20 of profit would give $6 to the Government, and $14 to the contractor. Therefore, there is a steep reduction in the contractor’s profit, whereas investment (costs) has doubled.

Again, interest costs due to delayed recovery are never a part of this calculation, but have to be borne by the contractor. Therefore, common sense dictates that there is every incentive for the contractor to minimise its costs to recover it and improve its profitability on investment.

If current assessments are true, then output from the block can never touch 80 mmscmd at its peak. What do you have to say?

Based on the production performance of D1 and D3, there has been unexpected reservoir behaviour, leading to significant deviation in production rate than initial estimates. This does happen in E&P industry, and there are a number of precedents globally, as well as in India.

Anyway, deep water oil and gas infrastructure is too expensive to build in an incremental or modular fashion. Therefore, any prudent development plan is built for the future, looking at the block as a whole.

Capital-efficient exploitation of the resources in KG D6 Block requires maximum utilisation of existing infrastructure/facilities in the block, while minimising an incremental addition on infrastructure. RIL, along with BP, is in the process of conceptualising an integrated plan for development of the block resources, and we expect to complete this effort by the later part of this year.

Does fresh field development plan also mean your investments in the block will undergo a change?

It is in the interest of RIL-BP to optimise their risk investments by providing maximum possible utilisation of existing infrastructure/facilities, and adding on minimal incremental facilities. However, the development of new discoveries would entail integration of development plans, leading to modification of the existing plan in order to produce new gas.

What has been RIL’s investment in the field till now? Has the company got its returns on investments?

The total spend in the block has been more than $8.6 billion. We are still recovering our costs, and have yet to earn any returns. Higher production and market-based prices as per the production-sharing contract are factors that will affect eventual returns. For any E&P company, the returns have to be seen on a portfolio basis. Considering this, having spent approximately $2 billion on E&P in NELP blocks, we are far from recovering our investments. Suppressed gas prices will only delay recovery of investments and act as a major disincentive for any future investments in deepwater basins of India.

How much has the Government earned till now by way of profit petroleum from D6?

The Government and the contractor share profit petroleum as per the formula given in the production sharing contract. As of December 31, 2011, the Government has received $80.2 million in profit petroleum share. This is in addition to $349 million as royalty on production. This is apart from income tax.

There are reports that BP differs with RIL’s assessment of D1 and D3. Is that true?

There is no question of any difference of opinion, as we are working together on all technical aspects with the common goal to maximise commercial production from the block.

Recently, approvals for the four satellite fields and declaration of commerciality for D34 fields in D6 block have been given. Does it mean that you may withdraw the arbitration notice?

These are two separate matters entirely. Let me clarify, RIL hasn’t given any arbitration notice on this issue. RIL has given an arbitration notice on a separate issue related to linking of cost recovery to actual production achieved vis-à-vis development plan production estimates. RIL insists that there is no provision in the production-sharing contract that allows the Government to do this.

Such production-linked cost recovery is nowhere applied globally, for the simple reason that any development plan provides only estimates and not commitments. Given the uncertainty of the oil and gas business, actual numbers always change.

Perception is that RIL jumped the gun as far as serving arbitration notice was concerned. What is the real provocation?

RIL and its partners have invested more than $8.5 billion of their own funds. This is not the Government’s money. In order to protect its contractual rights relating to recovery of these risk investments,

RIL has initiated arbitration proceedings as per the provisions of the production-sharing contract.

RIL has been seeking review of D6 gas pricing. Is there some difference with the Government on when the price should be reviewed?

The production-sharing contract has explicit provisions for sale of gas at the best available arm’s length price, so that it brings maximum benefit to the parties in the contract.

A contractor is bound to sell all gas at prices in accordance with the provisions of the production-sharing contract. With even APM gas selling at more than $4.2 per mmBtu and LNG selling at $14 per mmBtu, KG D6 gas prices are no longer aligned to market prices, as per the PSC.

Gas price, per se, has no global benchmarks, as is the case with crude oil. What, according to you, should be the actual basis of calculating gas pricing?

Gas has to be sold in accordance with the production-sharing contract which lays down clearly how gas prices have to be based on similar sales in the region as determined by the market. The region in which this gas is being sold is absorbing more than 50 mmscmd (more than 30 per cent of our domestic gas consumption) of LNG.

Therefore, there cannot be such a vast a hiatus between prices for a particular commodity in the market. Any market price has to be based on the opportunity cost involved. Therefore, the basis for pricing as per the PSC leaves little room for doubt.

Also, the production-sharing contractors under a particular contract are paid for crude oil at prevailing international prices.

Refineries also get paid import parity prices for their petroleum products. Then why should gas, which has a versatile use, and is environmentally a clean fuel, be discriminated against?

The recent intervention by the Government to regulate marketing margin… what is your take on that?

Marketing margin is contractually agreed between sellers and buyers to cover risks and costs associated with marketing, and with the full knowledge of the Government. Marketing margin has been around long before KG D6 gas came into the market. There cannot be different principles for its determination now.

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