Crude Oil

Crude Oil Reserves and Reserves-Production ratio

There are 26 sedimentary basins in India covering an area of 1.78 million sq km of which 1.46 million sq km are onshore and 0.32 million sq km are offshore in waters up to 200 meters in depth. The total prognosticated reserves are estimated at 20 billion barrels of oil and till date about 29% of this has been discovered. Thus a total of 5.8 billion barrels of oil have been discovered and with the annual production in the region of 35 to 40 mmtpa, these reserves are likely to last for the next 20 years. The Reserves/ Production (R/P) ratio of 20 compares favorably with the R/P ratios of all countries other than Middle East. However this would mean that the crude oil production will plateau at 40 mmtpa and the aggravating differential would need to be imported once the planned refining capacities come on stream. As per statistics published by Cambridge Energy Research Associates, as on January 1, 1996, the total proven crude oil reserves is 1011.3 bbl. India's share of reserves is thus less than 0.57%, even though its share of world oil consumption is about 2.2%.

Major crude oil fields and crude oil production

Of the 26 sedimentary basins, only six have been explored till date and six more have been taken up for further exploration. While ONGC operates on all the six basins currently under commercial exploitation, OIL is engaged only in the Upper Assam Basin.

The major oil fields are located in Bombay High, Ankleshwar in Gujarat and Upper Assam. The current exploration intensity is about 12 wells per 10,000 sq km as against the world average of about 100 wells, thus there is vast potential to explore untapped reserves.

Thus, India's crude oil production which was about 0.25 mmt in 1950 quadrupled to one mmt in 1960 with the discovery of Ankleshwar and Assam Oil fields. Discovery of Bombay High (North) in the mid-1970s and Heera, Gandhar and Bombay High (South) in the mid-1980s led to a quantum jump in oil production, with the total production peaking in 1991. The sharp rise in production in 1991 was due to post Gulf-war instructions, to NOC, to tide over the balance of payments problem due to rise in oil prices. The NOCs were however criticized for sub-optimally flogging the wells, this led to a series of corrective measures due to which production fell by 20% up to 1994. Although a sharp increase, from 27 mmt to 34.2, was reported in 1996 there has been a decline of about 7% in FY97.

The crude oil production of OIL has reduced over the last two decades from about
3.08 mmt in 1970-71 to about 2.88 mmt in 1995-96, partly due to social unrest in Upper Assam basin, where all the fields of OIL are located.

Though Bombay Offshore basin has been the single most important source for increase in oil production, there has been no major discovery in this region after Neelam Oil field in 1987, this is one of the main reason for flat production levels.

As per available data, the finding cost for ONGC is about US$1.5/ bbl, the production cost is US$1.3/ bbl. The exploration costs have been traditionally low, as the NOCs have concentrated their activities in proven areas and not ventured into high-risk areas.

Supply / demand equation

As stated earlier, the total crude oil production is about 35mmtpa, with no major oil field discovery in the last seven years. The total supply is likely to be around
35-40mmtpa in the next few years. The total refining capacity as on Mar '97 stood at 60.40 mmtpa. With the commissioning of IOC - Panipat in 1997-98 and
NRL - Numaligarh in 1998-99 and refinery expansions in Vizag/ Haldia/ Digboi, the total refining capacity would increase to 73.55 mmtpa by 1998-99. By the end of the Ninth Plan period, the estimated refining capacity would be about 163 mmtpa and therefore the gap between supply and demand would be huge. Thus, the crude oil producers should not have any difficulty in marketing their produce.

The crude produced by ONGC in the Bombay Offshore basin, typically about 38º API with about 0.03% sulphur, is considered to be very light and sweet and comparable with Nigerian Light Crude. The crude produced in the Onshore fields typically is about 32º API with about 0.20% sulphur and comparable with Minas crude from Indonesia. In our opinion, the crude produced in the Bombay High would trade at a premium to Saudi Light / Brent and other crude would approximately equate with Brent prices, strictly from purity and specific gravity of point of view.

The Government of India determines pricing of crude oil and the producer price was Rs967/ mt for about a decade up to 1992. Since then, the NOCs are being paid a 15% post-tax return on capital employed in addition to production costs. A significant portion of crude oil price consists of Oil Development cess at Rs900/ mt and royalty @ 20% of the well head price + cess and sales tax @ 4%.

We understand that the producer price has been increased to Rs1991/ mt wef
April 1, 1996. This in effect means that the total price of crude oil to refiners would be about US$13.60/ bbl against international prices ranging from about US$16-19/ bbl.

Unlike downstream refining and marketing, returns to E&P companies is based on 15% post-tax return on capital employed without any reference to the composition of networth and borrowings. Thus E&P companies are bound to gain if the cost of borrowings are lesser than 23.08% pa [15% divided by (1-tax rate of 35%)].

The low revenues paid to producers has resulted in insufficient resource generation which has in turn has affected the E&P activities resulting in plateauing of production. This problem has been partially addressed in the New Exploration Licensing Policy announced in Mar '97. All E&P companies including the NOCs would now be eligible for international prices in respect of crude oil extracted from new wells. Simultaneously cess has been abolished and royalty rates have been rationalized on crude extracted from new fields. The details of the new policy are given in the chapter on De-regulation.

Private sector participation and Production-Sharing Contracts (PSCs)

Private sector participation in the E&P sector started in 1974, by awarding exploration license. Although three licensing rounds were completed by 1986, no progress was achieved and the contracts had to be relinquished. The fourth licensing round was completed in 1991 when two blocks of the Bombay Offshore basin were awarded licenses. In 1993, the Government introduced a policy of round-the-year bidding and till 1995, eight licensing rounds were completed. Till the 8th round, the exploration cost was borne by the private parties and NOCs had to bear minimal license fees and enjoyed a carried interest of 30%. On discovery, the carried interest got converted to a participation interest and all revenues were first applied for recovery of exploration costs and the surplus was shared in the ratio of participating interest.

A major departure was made in the 9th round and bidding terms demanded that the contractor indicate the participating interest he is willing to concede to NOC, which can be a minimum of 25% and a maximum of 40%. Thus it proved to be a joint venture with exploration & production costs being shared in the ratio of participating interest.

Till date, four oil fields have been given for commercial exploitation to private sector players, of which the Ravva oil field has been bagged by the Videocon/ Marubeni combine and the Tapti, Panna & Mukti oil fields have been bagged by the Reliance/ Enron combine.

The Government has also floated two rounds of licenses for conducting speculative seismic surveys. The licensees are required to conduct geological surveys and make available data to upgrade the information on the country's hydrocarbon potential on a profit sharing basis. These speculative rounds have however elicited poor response.

The reasons for poor response both for exploration and seismic surveys can be summarized as under.

· Inadequate availability of geophysical data with the perception that the blocks being offered do not have the geo-potential for being developed into commercial fields

· The size of blocks offered is too small

· Time taken to award a contract runs into several years

· Several post-contract clearances are required to start the operations.

Natural Gas (NG) is derived from methane during the drilling of crude oil wells and is one of the most clean, efficient and environment-friendly fuels. The emission of Nitrogen oxide, Carbon monoxide, Carbon dioxide and Sulphur while NG is being burnt is negligible compared to other liquid petroleum products and coal. NG can either be transported in pipelines or liquefied and transported through specialized carriers as Liquefied Natural Gas (LNG). The calorific value range of NG is 9,000-9,500 kcal/ cubic meter. In terms of thermal efficiency, one billion cubic meters (bcm) equals one million ton of oil equivalent (mmtoe). Currently, all the activities that relate to NG are under the control of public sector oil companies. ONGC and OIL explore and produce NG and GAIL is engaged in storage, transportation and distribution of NG.

Natural Gas reserves and Reserves / Production ratio

The total NG produced in 1995-96 was 22,308 million cubic meters (MM3-MCM) as against 2,358 mcm produced in 1980-81.

Out of the production of 62mn standard cubic metres/ day (mmscmd), about 8 mmscmd is used for extraction of LPG / C2C3 and about 51 mmscmd / 18.36 billion cubic meters (bcm) is available for sale.

The production is estimated to increase to about 80 mmscmd in the next 2-3 years with the commissioning of various projects. It is likely to plateau thereafter, unless significant investments are made in this sector.

The quantum of NG that was flared up, due to inadequacy of infrastructure for transportation of gas, has significantly reduced over the last decade from a peak of
40% in 1984-85 to about 5% in 1995-96.

As per estimates published by MOP&NG, the total recoverable gas reserves in India are about 660 bcm, thus at 80 mmscmd the reserves are likely to last for about 25 years.

Distribution of natural gas

Gas Authority of India Ltd (GAIL) is the monopoly player in the marketing and distribution of NG. GAIL was set-up in 1984 for processing, storage, transmission, distribution, fractionation and marketing of NG. As per statistics published by MOP&NG, GAIL owns a pipeline network of more than 3,100 km, three LPG plants with an installed capacity of 479,000 mmtpa and other facilities for fractionating NG to produce value-added products like SBP and Pentane. GAIL has also commissioned pilot projects for marketing Compressed Natural Gas (CNG) in Mumbai, Delhi and Vadodara.

Presently the major consumers of NG in India are fertilizer and power industry. An inter-ministerial committee called Gas Linkage Committee (GLC) makes allocations. Any re-allocation due to temporary shortages in production amongst the consumers of NG is also decided by GLC.

GAIL builds and operates pipelines, across the country, for transmission of gas from the production/ landfall point to the point of consumption. The Hazira - Bijapur - Jagdishpur Pipeline (HBJP) the longest trunk route pipeline is one of the important sources for increase in demand for NG. HBJP capacity is being enhanced from 18.20 mmscmd to about 33.40 mmscmd at a project cost of about Rs24bn.

The transportation charges for all pipelines other than HBJP is fixed by GAIL in such a way that their costs plus a post-tax return of 12% is recovered on their equity investment in pipeline. In case of HBJP however, the return has been fixed by the government - based on Long Run Marginal Cost at Rs850/ tcm.

Pricing of natural gas and returns to producers

Up to 1986, the price of NG was determined by the producers themselves, based on the thermal equivalence of substitute fuels and the opportunity cost to the consumer. The price of gas thus varied not only from customer to customer, but also for the same customer, if the gas was used for different purposes.

In 1986, a decision was taken that the prices of NG be fixed by the government and accordingly a fresh pricing structure was to be implemented wef January 30, 1987. In 1988 the government set up a committee under the Chairmanship of Dr. Vijay L Kelkar, the then Chairman of Bureau of Industrial Costs & Prices, to examine the pricing of NG de novo. The report of the committee was considered by the Govt. and wef January 1,1992, the prices of NG was fixed for a period of 4 years up to December 31,1995.

A gas pool account was maintained and the difference between the consumer prices and producer prices for supplies to places other than northeast was surrendered to the pool and subsidy given in northeast was claimed from the pool. The subsidy in northeast was essentially given, as the law and order situation was not conducive to industrial activity and a major portion of the gas was being flared up.

As the pricing formula laid down by the Kelkar Committee was due for expiry in December 1995. In Jan '95, the government set up a committee under the Chairmanship of Mr. T.L. Shankar to review the entire question of natural gas pricing. The committee having submitted its recommendations in Dec 1996 is awaiting the decision of the government on its recommendations. While a price of Rs1850/ tcm continues to be recovered from the consumers.

Recommendations of the T.L. Shankar committee on natural gas pricing

The recommendations of the T.L. Shankar committee are summarized as under.

· The administered pricing regimes to continue till the year 2001-02. Any immediate move to de-regulate price could be counter-productive as it could result in a sharp increase in prices.

· The recommended pricing structure shall cover the period from April 1, 1997 to March 31, 2002.

· The recommended price structure for the period up to 2001-02 should be as under.

Major changes suggested in the pricing structure#include

Differential producer prices for ONGC and OIL.

Producer price for ONGC to increase from Rs1500/ tcm to Rs1900/ tcm and Rs1500/ tcm to Rs1800/ tcm for OIL.

Transportation charges for supplies through HBJ pipeline to increase from Rs850/ tcm to Rs1150/ tcm and thereby constant for the entire pricing period.

Prices for supplies to northeast to increase from
Rs1000/ tcm to Rs1200/ tcm with discount not more than
Rs300/ tcm as against the current level of Rs400/ tcm. Discounts to be given to units against the current policy of giving discounts on a case to case basis.

15% discount currently allowed for interruptible supplies be removed and instead discount be allowed only for supplies from isolated fields.

Existing gas pool to be continued and the difference between the consumer price and producer price be surrendered to the pool account. The subsidy on supplies to northeast be claimed from the pool account. OIL shall also claim its additional entitlement of Rs100/ tcm from the Pool account. The balance surplus in the pool account shall be utilized for development of small and marginal fields and funding R&D activities.

By 2002, the consumer price shall be Rs2,850/ tcm or US$2.30/ mmbtu, still lower than the landed cost of imports of US$2.70-3.50/ mmbtu. If the policy of market driven prices are to be put in place by 2002, an announcement should be made well in advance to enable consumers prepare themselves for an increase in feed / fuel stock.

The producer prices to ONGC/ OIL have been worked out - a 15% post-tax return on capital employed in line with the principle adopted by OCC for fixation of crude oil prices.

The cost of gas transportation along the HBJ has been estimated at Rs576/ tcm and Rs522/ tcm for 1995-96 and 1996-97 respectively. The downward trend in costs is due to the decreasing capital charge as the pipeline has been in existence for more than 9 years. However, GAIL has incurred substantial costs in upgrading the HBJP and thus the Long Run Marginal Cost (LRMC) of transportation is likely to go up with the commissioning of the upgraded pipeline in 1996-97. The revised tariff of Rs1150/ tcm has been worked out considering the LRMC and 12% post-tax return on equity, at an estimated 90% capacity utilization.

The option of equalizing transportation cost along the HBJ with other pipeline systems is not feasible. Transportation cost for each pipeline would thus have to be worked separately.

All new pipelines to have distance related charges and all potential customers to be notified about this fact in advance.

As private sector producers would have to be paid international prices for natural gas, a mechanism to compensate GAIL for the difference in the consumer price and the procurement price will have to work out.

Currently, charges are recovered on volumetric basis and not on basis of thermal content. In line with international practice, pricing should be denominated in terms of calories and a new system may be introduced along the HBJ pipeline in one year and in other areas within two years. The base prices as indicated above shall be applicable for a calorific value of 10,000 kcal/m3 for gas pricing and 8500 kcal/m3 for gas transportation.

ONGC and OIL shall examine the feasibility of guaranteed supplies for a guarantee fee paid by the consumers with a penalty for failure to fulfill the guarantees.

The government should examine notification of Natural Gas as "declared goods" under the Central Sales Tax Act to ensure that a uniform sales tax rate of 4% is payable by all consumers.

Given the oligopolistic situation for production & distribution of gas, a regulatory authority should be set up immediately.

As stated earlier, the price of NG is very low in comparison to alternative fuels/ raw materials and therefore the demand for gas has risen sharply. The demand registered with GAIL is about 96 bcm, more than four times the gas currently produced in the country. While the current supply of around 22 bcm is expected to go up to 28 bcm in the next couple of years, there is no certainty for any increase in production thereafter. The problem is compounded due to the worsening law and order situation in the northeast due to which, even NG currently produced is being flared up, as there are no takers even at a discounted price.

One of the alternate means of supply is transportation of NG either through pipelines or in liquefied form. Middle East holds nearly one-third of the world gas reserves and could be an important sourcing point for India. The GOI is already examining the possibility of setting up a pipeline from the Middle East. The possibilities of setting up a pipeline network linking Bangladesh, Burma and India are also being explored. GAIL along with ONGC and downstream majors has already setup a JVC for import of liquefied natural gas (LNG) for distribution in New Delhi.

Both the NOCs follow the "Successful Efforts Method" of accounting for determining the E&P costs. As per this method, all costs which are directly related to the discovery and development of commercially exploitable oil & gas reserves are capitalized to "Producing Properties" account. While general exploration costs including geological survey costs, costs of exploratory wells proven to be dry are written off as revenue expense in the year in which these are incurred or when the wells are declared dry. The unit cost of production is compiled under the following heads.

• Operating costs
• Recouped costs
• Financing costs
• Statutory levies

Operating costs#include cost of manpower, stores & spares, repairs & maintenance, insurance, overheads, cost of transportation of oil/ gas etc and all revenue expenses incurred in relation to production of oil & gas.

Recouped costs#include

(a) expenditure on survey and dry wells

(b) depreciation on fixed assets and

(c) depletion of Producing Properties.

While survey expenditure is booked as revenue expenses in the year of incidence, exploratory drilling cost along with depreciation cost on assets deployed in such drilling are initially capitalized and charged to P&L a/c only in the year in which the well is determined to be dry. Depreciation on assets deployed in exploration & development is initially capitalized as activity cost and prorated over the years or written-off in the respective year if the activity proves unsuccessful. All amounts capitalized as Producing Properties are depleted over proven recoverable reserves by arriving at a per unit depletion rate and multiplying the per unit rate with the oil & gas produced from that field.

Financing costs directly relate to procurement of capital assets and exchange variation on foreign currency loans utilized for acquisition of fixed assets are capitalized and other financing costs are charged to revenue account.

Statutory levies#include royalty, cess, octroi, sales tax and turnover tax. With the exception of turnover tax, all other levies are recovered from the consumers.

Wherever any of these costs are joint and are not separately identifiable, they are allocated between oil and gas in the proportion of actual production taking 1000 M3 of natural gas as one mt of crude oil.

With the widening gap between demand and supply, both for oil & gas, the outlook for the upstream sector is extremely positive. The decontrol of the sector would give more strength to these companies to pursue their goals with greater vigor. In our opinion, natural gas could turn out to be a dark horse for the E&P and Distribution companies. The New Exploration Licensing Policy has already given a thrust and direction to the reforms in the upstream sector, with virtual decontrol of the sector for oil & gas explored and produced in new oil fields. The details of benefits that would accrue to the oil companies in the event of full decontrol are discussed in detail in the chapter on De-regulation.