MonitorsPublished on Aug 30, 2006
Energy News Monitor I Volume II, Issue 10
Energy security in India: Issues and Policy Perspectives - III

(By Dr. Samir R. Pradhan)

External or Foreign Energy Security Issues and Strategies

The past few years have witnessed lot of deliberations, discussions and actions on the external or foreign dimension of India’s energy security. This is carried through basically in the ambit of energy diplomacy and economic diplomacy. The activities in the external or foreign dimension of India’s energy security are evolving to take a concrete shape. The current status of such deliberations and actions point to some successful achievements as well as emerging challenges in the years ahead, which make a case for devising concrete policy perspectives. However, there are some issues that merit a discussion, so that possible policy perspectives can be envisioned.

1.        The Strategy

The current strategy adopted by India to pursue its energy security interests abroad envisages substantial reliance on ‘energy diplomacy’ and less stress on ‘economic diplomacy’ and on other traditional strategies such as military and strategic diplomacy. The current approach is basically bilateral and plurilateral, though there is strong inclination towards regional and multilateral engagements to ensure energy security. The policy making is still at an evolving stage evincing dilemmas, contradictions and complexities. Though the present government is fully convicted towards prioritizing the external energy security dimension and has initiated some institutional arrangements in this regard, yet there are substantive issues and perspectives that need to be comprehensively addressed before venturing outside.

2.       Market Vs. Geopolitics: The Path to Choose

There is inherent dilemma with respect to reliance on market solutions or on enabling geopolitical configurations to address the external energy security concerns. While on the one hand, the global energy sector, especially the world oil and gas sector, has transformed into a pattern of integrated and interdependent structure in the ambit of market liberalization and Globalisation; on the other hand, there are clear trends of energy geopolitics in the regional context consequent upon the structural transformation of the world oil and gas regime owing to the paradigmatic global economic shifts. This makes it imperative to tread a cautious path between market fundamentals and geopolitical considerations. There is somehow ambiguity in the sense that India’s integration with the existing world energy system will be spontaneous on the basis of its emerging market fundamentals or it has to carve a niche for itself in the system.  Energy (oil and gas) being a composite good (both economic as well as strategic) makes concrete policy designing unobtrusive. Therefore, it seems pragmatic to adopt a judicious balance between the twin imperatives of market and geopolitics while pursuing external energy security.

·          Equity Reserves Abroad: Economic Rationality vs. Strategic Considerations

Given the ‘region specificity’ characteristics of the world oil and gas reserves and the overwhelming presence of super majors and consequent highly restricted entry in the traditional energy bastions, the emerging major consumers like China and India are aggressively venturing into some new off-beat energy producing countries or regions, thereby making these places as global hotspots. It is obvious that clinching equity oil and gas deals in such regions may not be always based on rational economic principles rather than on other considerations. This has become an issue of concern for India as it is loosing out potential equity oil and gas deals due to the aggressive Chinese posturing. This again exhibits a policy perplexity as to prioritising hard-nosed commercial principles or strategic calculations in clinching equity oil and gas deals. In other words, the issue becomes to collide and compete or cooperate. Though there are manifestations of cooperation, yet there are bound to be apprehensions regarding the intention of others, especially, China, as the Chinese would cooperate till their other interests are not hampered. The way out seems to be ‘cooperative competition’, i.e., cooperate where you cannot compete, and compete where you can leverage your advantages.

3.       Energy Cooperation: Sub-regional, Regional or Multilateral cooperation

Energy scarcity is a potential aspect, which can catalyze cooperation and economic integration in Asia by balancing the respective deficits and surpluses in an interdependent framework among the nations. Nonetheless, the real issue is to what approach should be adopted by India. The key seems to be emphasis on a phased approach, first prioritising energy cooperation at the sub-regional level (South Asia), then at the inter-regional level (with the expanded neighbourhood in the East, Central Asian region, Gulf region, North Africa, Latin American countries and with the OECD/IEA member countries), and lastly on a pan-Asian level. To culminate at the level of accelerated regional energy cooperation, India should adopt a gradual step-by-step approach. This will help in removing the traditional mindsets among the countries in Asia as well as in asserting a new energy identity. Side by side, India should leverage its emerging status as a global energy player at the multilateral level by actively participating in the activities and deliberations of various multilateral organizations like IEA, OPEC, etc.

Though there are some positive developments in recent years, yet there are certain overriding economic and geopolitical factors that may hinder pursuing India’s energy security in the coming years, unless a concrete policy perspective is not adhered to. In this regard, the cabinet nod for going with negotiations on three cross border pipeline projects such as, Myanmar-Bangladesh-India, Iran-Pakistan-India, and Turkmenistan-Afghanistan-Pakistan-India are worth mentioning. In this regard, there is imminent need of comprehensive interdisciplinary study focussing on the vital aspects of such projects to India’s interests.

·          Institutional Frame work for regional cooperation

The long-term strategy pertaining to the external dimension of India’s energy security should focus on viable pan-Asian energy cooperation. In this regard, attempt should be made to focus on some sort of institutional arrangements for facilitating negotiations regarding each and every country’s energy concern. With the changing dynamics of world oil and gas market, there are immense potentials for regional cooperation through balancing the requirements and concerns of both energy surplus and energy deficit countries by accelerating the operation of the overall energy value chain from exploration to dispensing. This need huge investments and regional trade flows. Besides the commercial energy, there is enormous scope for cooperation in the renewables. This imperative calls for searching for an institutional arrangement. In this regard the experience of IEA and ECT can be replicated with some changes in the context of Asia. People often doubt the viability of such regional institutional arrangement that may contradict the existing institution like the IEA, but the conditions and realities of the Asian countries are totally different from those of the IEA countries, so it is crucial to establish such institutional arrangement within Asia that may comprise all producing and exporting as well as consuming and importing countries/regions.

Moreover, since Asian countries are all in the process of deepening globalization and hence depend on market solutions for their domestic resource constraint, they should seriously exploit the globalization framework to solve the problems of ‘energy poverty’ or ‘energy plenty’. In this regard they should try to evolve an Asian Energy charter that may facilitate regional trade, investment and information sharing in the energy sector.

Though India is actively trying to foster regional framework for energy cooperation in the ambit of various foras such as organizing a round table conference of major oil exporters and consumers in Asia, incorporating energy cooperation in all bilateral economic agreements with different Asian as well as other countries, yet the policy strategy needs to be carefully examined in the context of some Asian countries such as China and others are aggressively pursuing the sub regional energy cooperation bereft of India. This makes the importance of devising well-guided external foreign energy policy.

4.       Leveraging Voluminous Energy Imports through expanded Trading relations with the exporting countries

The key strategy of survival and sustenance in the global economic regime has been leveraging one’s comparative advantages to address one’s limitations and deficits. In recent years, countries that are overwhelmingly dependent on energy imports have tried to use their economic strength as a leverage to bargain or to appropriate concessional gains with the exporting countries. The Chinese activities are noteworthy. In recent years, China, recognizing its imminent dependence on the Gulf regions for its oil needs, have progressively expanded its bilateral trade profile with the countries in the region and also have clinched cross energy investment deals with Saudi Arabia, another major player in the world oil game. In such a competitive and intense environment, India should reenergize and expedite impending policy decisions pertaining to its economic diplomacy, so that its energy interests can be actively pursued.

5.       Security of Sea Lanes of Communication (SLOCs)

One of the important implications pertaining to the external dimension of India’s energy security in the environment of increased imports through tankers, VLCCs, LNG vessels, etc point to the strategic aspect of the security along the over crowded SLOCS or what is called ‘strategic chokepoints’. This two such points, namely the Strait of Hormuz and the Strait of Malacca, which are of considerable strategic importance to India’s energy security.  There are certain issues such as the security of maritime routes, which should be undertaken seriously through various regional bodies such as SAARC, ASEAN and GCC. In fact, issues such as development of the deep-sea port of Gwadar on the Makran coast of Baluchistan by China and accelerating engagement of China with Maldives (situated on the Indian Ocean Rim, (close to the Andaman-Nicobar Island), are of immense strategic importance to India.


The region specificity of India’s current and future energy imports especially, that of oil and gas is bound to have severe repercussions on the country’s energy security. This concern will be substantial in the environment of integrated globalized energy market where a cyclic or isolated incident impinging supply disruption anywhere can affect all. Since energy security is influenced by geopolitics as well as market fundamentals, the imperative is to maintain a judicious balance while devising a country’s internal as well as external energy security strategy.

As the above discussion shows the various current and emerging issues of India’s energy security makes a case for a clear coherent and comprehensive energy policy planning focussing on short-term or immediate and long term imperatives. The short-term strategy pertains to internal issues such as devising a national energy policy, enhancing domestic energy portfolio, synchronizing reforms in all energy sub-sectors, and coordinating regulatory structures and obviously an integrated resource planning and preparation for emergencies through buffer stocking. The medium term and the long term highlight the external dimension, which signifies the viability of a pan-Asian energy cooperation, and emphasis on expanding trading portfolio with the import sources to leverage against any possible vulnerabilities. Moreover, the study highlights the immediate need for comprehensive research and information dissemination by encouraging inter disciplinary think tanks, to contribute substantially in policymaking.

Selected References

1.         Bayne, Nicholas and Stephen Woolcock, The New Economic Diplomacy, England: Ashgate Publishing Ltd., 2003.

2.        EIA, Strategic Chokepoints, US Deptt. Of Energy, available on the site, <>.

3.        IEA, Towards a Sustainable Energy Future, Paris; IEA/OECD, 2001.

4.        Ministry of External Affairs (MEA), GOI, “Speech of the Minister”, available on line at <>

5.        Ministry of Petroleum and Natural Gas (MoPNG), Hydrocarbon Vision 2025, Government of India, 2002.

6.        Planning commission, Tenth Five Year Plan Documents, GOI, 2002.

7.        Pradhan, Samir R., Interdependence and Mutual Vulnerability: Issues in oil Security, Chapter IV, Unpublished Thesis, Jawaharlal Nehru University, New Delhi, 2005.

8.        RIS, Energy cooperation in South Asia: Potential and Prospects, Policy Brief, RIS, New Delhi, No. 8, 2003.

9.        TERI, “TERI Energy Data and Directory Yearbook”, TERI, New Delhi, 2003-04.

10.     United Nations, World Energy Assessment and the Challenge of Sustainability, United Nations, 2001.

11.      Various Newspapers and web sites.

(… to be continued)

Power Sector Reforms in India: Power to the Farmer


(Courtesy: APARC Stanford IIMB Management March 2004)

T L Sankar

Q: Why do utilities charge different rates to different consumers?

A: Firstly, the cost-to-serve for each category of consumer varies depending on several factors. There are technical reasons such as power factor, voltage of supply and so on, which are set out in the Electricity Supply Act, 1948. There are also commercial reasons. In some situations, the total quantity of power available could not be sold, unless some categories of consumers we are charged a lower tariff. There are also considerations of equity or the need to meet the merit wants of the poorer population, which prompted differential pricing.

Q: In effect, there is a base level called appropriate tariff and if the actual rate charged is kept lower, the difference from the base level can be called a subsidy.

A: Correct. Of all the Electricity Regulatory Commis-sions (ERCs) that have given tariff orders only two, namely Andhra Pradesh and Haryana, have adopted the concept of cost-to-serve whereas other ERCs, on the basis of same level data availability, have stated categorically that the data was inadequate to estimate the cost-to-serve. So if one talks with reference to long-run marginal cost as base level cost then every consumer in most states would be considered as getting a subsidy. But if the average cost is taken as the base level, tariffs for agriculture and small households are below the base level and they would be called subsidised categories. Whereas if cost-to-serve is taken into consideration, agriculture may not be getting any subsidy at all in view of the supply being restricted to specific hours, including mostly non-peak hours of the day. If all factors are taken into costing the actual cost-to-serve, agricultural demand may be lower than the average cost! Let us begin with the differential pricing based on technical characteristics of the supply. The Electricity Supply Act 1948, suggests that tariff to the consumer should be determined with reference to the voltage of power supply, the power factor and other technical details. Supplies which are taken at high voltage such as 133 kV or 33 kV are subject to limited number of transformations and lower transmission loss while supplies which are to be effected at LT i.e., low tension levels require to be stepped down and distributed through a system with further technical and non technical losses.

Q: But some say that supplies should be charged differently for different hours of the day, which is called Time of Day (TOD) tariff.

A: Yes. In any power system, especially in India, during the late night and early hours of the day, say from 10 pm to 5 am, the power supply is in excess of demand, while during the morning hours supply is inadequate to meet the demand. During certain hours like 6 pm to 9 pm the demand is the highest due to the lighting needs of households and commercial establishments and these are called the peak hours.

Q: Supply at nighttime, then, should be priced very low. Agriculture gets supplies mostly at night.

A: Yes. There is another way of looking at it. Electricity charges have two parts – capacity charge and energy charge. Capacity charge is the fixed costs, which are related to the costs of setting up and maintaining the power plants, transmission and distribution lines. This capacity charge should be borne by those who use the system during the peak hours, as their demand cannot be met without the requisite capacity. But during the off-peak hours only the variable costs or the energy costs may be collected, as the capacity charge has already been collected from peak hour users.

Q: So for agricultural consumers, cost-to-serve would be much lower than the average cost of supply.

A: There is another reason to charge agriculture less. Agriculture does not get supply for all the 24 hours of the day but only at times fixed according to the convenience of the utility. Such supplies, called ‘interruptible supplies’, should be charged about 25% to 30% lower than the rates for guaranteed supply for 24 hours. I have calculated that in most states if you take away the fixed costs or the capacity charge and give a further 20% reduction we end up with the agriculture tariff at about Re1/- or less. Agriculture does not get supply for all the 24 hours of the day but only at times fixed according to the convenience of the utility. Such supplies, called ‘interruptible supplies’, should be charged about 25% to 30% lower than the rates for guaranteed 24 hour supply.

However, some ERCs like Andhra Pradesh have estimated it at just below the average cost. Such ERCs have a duty and responsibility to explain the method used and details of consumption pattern assumed for different categories of consumers to all consumers. The data and methodology on the basis of which any agency arrives at the cost-to-serve in respect of different users should be put to open debate. But I feel that this controversy regarding cost-to-serve and cross-subsidy will keep on arising at different points of time and will be interpreted by different people and different judicial courts differently. The Calcutta High Court and Supreme Court interventions introduced a situation whereby cross-subsidy should be eliminated totally. Now the power entities would take the stand that the cost-to serve if properly interpreted would lead to differentiations in the prices between consumers. There are no universally accepted principles or procedures on which cost-to-serve could be calculated. I therefore feel that we should find a lasting solution to tariff determination, which would serve fully our ideas of efficiency as well as equity.

Q: Is such a solution possible at all?

A: Yes. Especially in the context of our unbundling utilities into generating companies, transmission companies and distribution companies. What has been done is only the first step. The full advantages of competition, which alone can bring about efficiency in a sustainable manner, can be obtained if we unbundle the generating companies into smaller generating units competing with each other to market the power produced by them.

Let us visualise what happens when there is no single utility to service the needs of all consumers in a specified area. If the power market becomes a free market, where each producer can sell to any consumer at a price mutually negotiated, and the entities which operate the transmission and distribution become only transport agencies to take power from places where it is produced to points where it is consumed, there should be no need to aggregate all the power produced by state generating companies. The consumer will have to pay to the producer of power the cost of production and to the distribution companies the charges for transport, which will include the cost of power, which is lost in the process of transmission and distribution. That is the ultimate system we want to achieve but to begin with, this would be possible only for consumers who use only the transmission system and take power at high voltage. (Distribution wires will not be open for competition for some more time.)

This is the power scenario visualized in the Electricity Bill (now Act). The Bill expressly prohibits the transmission company from dealing with power purchase or sale. In such a system neither economic theory nor efficiency imperatives suggest that the generating costs of all generating plants should be pooled and the sale should be at the average cost. The correct measure to improve efficiency is to enable each generating plant to sell power at a different price with reference to its costs of production. For example, the National Thermal Power Corporation (NTPC), the largest single power producer in India, has old power stations, like Singrauli, where the cost of generation as per our normal commercial principles is very low. NTPC also has recently commissioned plants where the costs of generation are as high as Rs.2.3 per kWh. But each plant has separately contracted to supply its production to different electricity boards. In fact many SEBs get power from NTPC stations at the same location at different rates.

Q: Will not such a system create disincentives to the producer?

A: You must have been listening to a clever ‘free market economist’. In the power industry, each power plant is set up after a power purchase agreement is settled with the persons/agencies who will purchase that power. The buyer agrees to a price, which covers all the costs of production, and usually it varies each year with the changes in capital cost with gradual depreciation. Since the consumers have paid for the total costs, as and when they were incurred, they cannot be denied the benefit of having a lower price from the generation in the old plants where depreciation brings down the value and interest on loans. Based on the generation cost, if we group together power plants into ‘low cost’, ‘medium cost’ and ‘high cost’ supply groups, each of these groups can negotiate and sell power to a selected group of consumers. Better still, the power generation plants can be disaggregated so that each project becomes a profit center and can sell directly to the consumers.

Q: Will this not create a lot of problems? Technically, if you segment the power system into small groups of power stations, the operation of the power system cannot be done at the optimal level by the systems operator.

A: The separation of the generating system and linking each sub-system to a group of consumers is only for the purposes of costs. The system operation will continue on the existing lines using the best rules for optimal system operation and grid regulation. Even now it is being done because power from different power stations, which have different costs, are fed into the system and the consumers are charged differently. Different consumers can pay for power on the basis of the source of supply. This is done in all ‘wheeling agreements’. A system operator will have no new problems in operating what is proposed here.

Another way of putting the proposal is to use the terminology of the Maharashtra Energy Review Committee, July 2011. They have suggested that some of the existing contracts for power supply to the SEB including from state owned Genco could be ‘assigned’ to certain discoms. We are proposing the same thing.

Q: What is the purpose of such a new proposal, which does not change any technical features of the power system?

A: It does change drastically the commercial aspects of power sector management with government managing its power resources in a manner, which would meet some public policy objectives. The cheapest power available with the government is ‘assigned’ permanently to the category of consumers considered deserving of a cheap supply of power on grounds of equity or to promote socio-economic development.

Q: Why cannot the current system, where all costs are billed together and ultimately the deserving categories are supplied power at lower rates by cross-subsidisation, be continued by declaring that the low rates would continue on a long-term basis?

A: What we now call  as cross-subsidisation is an illusion. It is the result of an accounting system that we have adopted when the utility was specifically defined as a single, sole monopoly supplier of all power needs in a designated area and had a responsibility to supply all demand. Pooling of only some parts of the generating station has no logic when unbundling is effected, and the ‘single buyer’ model is to be abandoned.

Based on the generation cost, if we group together power plants into ‘low cost’, ‘medium cost’ and ‘high cost’ supply groups, each of these groups can negotiate and sell power to a selected group of consumers.

Q: But will not the solution you propose, deny cheaper sources of power to the other consumers?

A: Not in actual practice. No government or ERC is actually charging the agricultural consumers a tariff anywhere close to what the government advisers compute as the cost to serve the farmers. As of now, the non-agricultural consumers pay much more than what they might have to pay under our new proposal. The present tariff policies only threaten the farmers that anytime their tariff could be increased from the current tariffs, which are very low! No government today denies the responsibility of a welfare state to provide minimum needs at affordable prices to poor households. But regarding poor farmers, have you ever asked a farmer what is the tariff he would like to pay?

Q: Yes, several times, and the answer is the same always. He would like to pay that amount which the canal irrigation farmers pay for supply of water of the same quantity. Irrespective of whether farmers get water from canalirrigation or well-irrigation, they face the same market and other economic conditions. In fact, the pump irrigation farmer usually operates in more hostile soil conditions and has taken a high risk in digging a well and investing in the pumpset etc. He feels that a just and fair government should provide water or electricity at a reasonably low rate so that both kinds of farmers get equal benefits or costs. Further, no farmer expects the power companies to subsidise power but would like the government to run the power companies efficiently and provide the subsidy to the required extent, and operate it just like the fertiliser subsidy or kerosene subsidy. But the government says it does not have the money to take up this subsidy. Also, eminent economists advise that subsidy is bad and should be done away with, especially in the context of globalisation. Are these views wrong?

A: Both the contentions are wrong. If the need for a subsidy is real, any government worth the name should find the resources. It is the duty and responsibility of the government. All governments in the world give large subsidies to agriculture. The French and Japanese subsidies to agriculture are well known. Recently a World Bank study has brought out in detail the large extent of subsidy to the US farmer. Further, if the government accepts our suggestion to ‘assign’ the low cost power generating stations to agricultural consumers and poor households, it will not have to raise these additional resources to provide electricity services at low and affordable prices to farmers. There are several ways of doing this. Some very detailed proposals for Andhra Pradesh and Karnataka have been published2. There is a very lucid exposition on the new proposals by Dr A K N Reddy3.

Let us take the Karnataka power sector, for example. Of the total ‘sale’ to all consumers in 2002-03 of 21997 MU, the subsidised sales is for Kutir Jothi (KJ) and Bhagya Jothi (BJ) households who have only one bulb, and to agriculture. The number of KJ/BJ households was 2.06 million and they consume 446 MU. The number of agricultural pumpsets was 1.22 million and they consumed 8270 units (estimates are as made by Karnataka Electricity Regulatory Commission). In subsidising power to agricultural pump sets, the correct procedure would be to separate out small and marginal farmers and supply them with least expensive power.

In subsidising power to agricultural pump sets, the correct procedure would be to separate out small and marginal farmers and supply them with least expensive power. But the data is not available to do so.

But the data is not available to do so. Therefore, of the average consumption of each pump set assessed as 6779 units per year, we may supply only 4000 units per pumpset, which might be adequate for the small and marginal and even middle class farmers. The least cost power supply to agriculture would need 4880 MU and supply to KJ/BJ households another 446 MU, making a total of 5326 MU. There would be a further consumption of 3390 MU (which could be called Agriculture II) by the agricultural sector, which could be charged a tariff equal to the cost to serve, calculated along with all other categories of consumers.

Q: How does one compute the appropriate tariff for this special category who would be charged a special rate?

A: The innovativeness of our proposal lies only in the fact that we propose to segment the power supply system into least cost supply system and the normal supply system. To reach the KJ/BJ households and the agricultural pumpsets power has to pass through the Karnataka Power Transmission Corporation (KPTCL)’s transmission and distribution system and the loss of 28% in this should also be provided along with the final consumption of 5326 MU. We also intend to propose some long-term tariff for the special category.

The two fundamental issues in supply of power to agriculture are metered tariff vs flat rate unmetered tariff and direct subsidy vs tariff subsidy. The fomer should be seen in the context of two part tariffs with a fixed ‘access’ charge and per unit charge.

We assume the loss due to transmission and distribution to be 20% as it is planned to be achieved in three to four years. So we have to segment from the supply system of generating plants, those, which have the least generating, cost per kWh upto 6658 MU. In Karnataka, we are able to identify hydel stations of old vintage which can provide power to the extent of 6658 MU or more at Rs 0.466 /kWh. If we add the operating cost of the power entity which is Rs 0.606 /kWh and allow for the 20% loss, the delivered cost to the farmer would be Rs1.34/kWh.

Q: This is about the same as the costto- serve, according to the principles discussed earlier.

A: Correct. Rich farmers or all those who use above 4000 units per pumpset might have to pay the cost-to-serve which might be a little over Re 1/- per kWh. Upto 4000 units, let us assume the government feels that on grounds of equity – vis-à-vis, the canal farmer and any other consideration, should be only Rs 0.50 per unit. The government would then have to bear the subsidy to the extent of 83 paise per unit on 5326 units. This would amount to Rs.442 crores (4.42 bn).

Q: Do you think these proposals would make farmers accept ‘metering’ of pumpsets?

A: Yes. If farmers are not only assured that the tariff would not be increased but maintained at say Rs 0.50 /kWh for 10 years, and shown how the procedure of assigning them the low cost generating plants ‘empowers’ them, they would agree. Farmers would further be enthused to maintain the meter in working condition, if the tariff instead of a flat tariff for 4000 units, is arranged as a progressive tariff starting at 25 paise and ending at 60 paise per unit. Farmers, especially small farmers would attempt some conservation efforts too.                      (… to be continued)

India’s Reforms in the Hydrocarbon Sector

What Has Been Accomplished? What Remains to be Done? - XVI

…continued from Volume 2 Issue 7  ( … to be continued)

Reforms in the Downstream Segment: 1995-2005: Product Pricing 

Evolution of the product pricing regime

It is necessary that we visit the history of product pricing before we try to understand the difficulty in dismantling the Adjusted Price Mechanism (APM) that has so far, been the basis for petroleum product pricing.  Till 1939 pricing of petroleum products was generally market determined.  In the case of Burmah-Shell, its UK office advised day-to-day prices to which additional transport costs and local taxes was added depending upon the regional market segments.  Between 1939 and 1948 oil companies like Burmah Shell, Stanvac and Caltex operated a price pool for Kerosene / Motor Spirit.  For High Speed Diesel (HSD) day-to-day prices were fixed by the individual oil companies.  Between 1948 and 1958, the Value Stock Account (VSA) agreement between the Government and Oil Companies formed the basis for pricing of major products like Motor Spirit, Diesel, Kerosene, Aviation Spirit, Aviation Turbine Fuel, Light Diesel Oil, Furnace Oil Etc VSA prices were on import parity lionked to “Abadan’ in Iran.  Burmah-Shell as market leader maintained separate VSA for each product.  Other companies followed the prices fixed by Burmah-Shell.  At the end of each year, collections at provisional basic selling price were set off against actual costs.  Resultant surpluses/deficits certified by auditors were advised to the government.  Surpluses/deficits were either ploughed back/recouped from the market by adjusting selling prices.  The last price revision under the VSA took place in 1957 after which it was terminated.  This was followed by an ad-hoc agreement during 1958-61 wherein it was decided that recovery of deficit balances must be withdrawn. In 1960 Oil Price Enquiry Committee (OPEC) was appointed by the Government under the Chairmanship of Shri K R Damle, to make recommendations for a new price formula.  The recommendations were implemented in 1961 with prices being linked to lowest posted prices at Abadan in Iran by any of the four companies operating in India, less prescribed discounts. While implementing the recommendations during 1961-65, the Government maintained the existing ceiling selling price and the difference between market and selling price was collected through irrecoverable duties.  The ceiling selling price was adjusted for statutory levies, variations in FoB costs/ocean freight were to be debited/credited to C&F adjustment account which was submitted to the Government every quarter. In 1964 the Government set up a Working Group on Oil Prices (WGOP) under the chairmanship of Shri J N Talukdar to look into the pricing mechanism. While implementing the recommendations in 1966-70, the Government decided in favour of full FoB prices liked to posted prices at ‘Bandar Mahshahr’ in Iran. In 1968 the Government set up the Oil Prices Committee (OPC) to determine the future ceiling selling prices.  The committee submitted its report in October 1969 which was implemented in 1970 and this environment prevailed until 1975. Ex-refinery prices continued to be determined on notional import parity with Bandar Mahshahr in Iran as the Reference Port.  Inland refineries were made pricing points in addition to main ports.  In order to compensate for under-recoveries of inland refineries, the Freight Surcharge Pool (FSP) was introduced.  Thus the process that started from market determined prices slowly evolved with increasing degrees of control by the government and culminated in what is known as the Administered Price Mechanism (APM).  The APM tariff structure for petroleum products were based on considerations of revenue for the government, price stability (insulating the market from international oil price volatility) socio-economic considerations (cross subsidization of products to weaker sections of the society), as well as energy conservation (repression of energy use or demand management).  Under the APM regime, retention price of products was fixed separately for each refinery based on standard throughput, standard product pattern, standard fuel and loss percentage, refining cost and return.  The retention concept was also extended to marketing companies for determining the storage price of products.  The basic price (ex-refinery price) was uniform for all oil companies.  The selling price of the products to the consumer was kept uniform by adopting an average market cost plus margin.  The variation between: (a) The actual crude price and the pooled FoB price (b) The retention price and the ex-refinery price (c) Retention marketing margin and the average marketing margin was balanced through a set of pool accounts (Oil Pool Account) controlled by Oil Co-Ordination Committee (OCC).  However this mechanism had envisaged oil prices moving almost equally in both directions when in reality it moved primarily in one direction – up - in reality.  As a result the deficit in the Oil Pool Account began to swell.  By the 1990s it was clear that APM was unable to deliver little on most of its ultimate objectives without imposing huge costs on the overall economy in general and the oil industry in particular. Dismantling of the Administered Pricing Mechanism (APM) has been recommended by every committee or commission set up to review reforms in the petroleum sector.   In 1995 the strategic Planning Group or the R-Group recommended that APM be phased out gradually and replaced by ‘free market mechanism’.  In 1996, the Expert Technical Group (ETG) in its second report recommended phased dismantling of the APM regime suggesting appropriate duty structure within the constraints of the Oil Pool Deficit. 







ONGC to join Sinopec and CNPC

Text Box: • Collaborative bidding to keep prices in check
• MoUs to be signed between the companies in the near future
• Chinese companies said to have shown interest in joint bidding
• ONGC is also in talks with Nigeria, Cuba for E&P 

 August 30, 2005. Oil and Natural Gas Corporation has decided to tie up with China National Petroleum Corporation (CNPC) and Sinopec, for jointly bidding of exploration and production (E&P) activities abroad. The three companies would jointly bid for E&P projects in Africa, Central Asia, Latin America and the Middle East. India may sign a memorandum of understanding (MoU) with the Chinese companies in the near future. An Indian joint task force under the aegis of the ministry of petroleum and natural gas visited China early this month and the Chinese companies has shown keen interest in associating with India for overseas E&P activity. However, India have not received any communication from the ministry as of now. All the three companies, however, have been competing for global E&P projects. Some time back, Sinopec had outbid ONGC Videsh Limited (OVL), a subsidiary of ONGC focusing on E&P projects abroad, from taking Shell's 50 per cent equity in Angola's Block 18. On the other hand, ONGC outbid Sinopec and CNPC in Egypt and Qatar. Moreover, CNPC is OVL's contender for EnCana's oilfields and pipeline in Ecuador. ONGC is in talks with the government of Cuba for E&P projects, while for Nigeria, the company is gearing up for the bidding process.

Country’s first deepwater gas by ’06: ONGC

August 28, 2005. OIL and Natural Gas Corporation will deliver the country's first deepwater gas in April 2006. The gas production from the G-1 and GS-15 blocks of Sagar Samridhi deepwater field in the Krishna Godavari basin will be to the tune of 2 mmscmd. The G-1 and GS-15 structures were significant as the ONGC locations where India's first digital oil fields were being developed. It is also planning to drill 12-16 more wells during the current fiscal at Sagar Samriddhi. It is also ready to commence two new production fields on the western coast - Delta-1 and Delta-33, both shallow fields in Mumbai High. Delta-1 will commence production in January 2006 with 3,000 barrels of oil a day while D-33 is expected to start production by December 2006. The D-33 block is yet to be officially ratified, but indications are that it will be good for 15,000 barrels of oil and two mmscmd of gas a day. The oil and gas major's capital expenditure that stood at Rs 10,400 crore (Rs 104 bn) last year is all set to be repeated this year. One of the ongoing projects is the phased replacement of the 4,000-km subsea pipeline laid in the mid-70s, contract for which has been awarded to the L&T-Global Offshore consortium and will cost ONGC $400 mn (Rs 17.45 bn) in the 2005-08 period.

GAIL to begin drilling in Bengal basin

August 28, 2005.  GAIL (India) Ltd, which plans to invest approximately Rs 600 crore (Rs 6 bn) in exploration and production (E&P) activities over the next three years, is all geared up with Gazprom to drill its first offshore well in October in block-26 in Bengal basin. The consortium has already invested $13 mn (Rs 567 mn) and expects to invest another $30 mn (Rs 1.31 bn) for the first well. The drilling activities will continue till the end of November 2005.

The GAIL-Gazprom consortium was awarded exploration block-26 in the Bengal basin as part of the first bidding round under the New Exploration Licensing Policy (NELP) in 2000. GAIL has a 50 per cent equity participation in the block with Gazprom as the operator. The block is located around 100 km south-east from the Haldia port in West Bengal. Environmental clearance has been obtained from the Ministry of Environment and Forests (MoE&F) and Directorate General of Hydrocarbons (DGH) for carrying out drilling activities. Moreover, the consortium is gearing up to drill a second well for which another drilling rig is being finalised. The consortium has already completed geological and geophysical survey of the block. The commercialisation of the block of Cambay basin was expected soon. As of now, production was being planned with an estimated recoverable reserve of 3.5 million barrels, for 10 years. GAIL along with Gujarat State Petroleum Corporation has struck oil in the Cambay basin block.


HPCL, BPCL eye stake in Singapore Petro

August 29, 2005. State-owned oil companies, Hindustan Petroleum Corporation and Bharat Petroleum Corporation are actively pursuing plans to pick up equity in the $5 bn (Rs 219 bn) Singapore Petroleum Corporation (SPC). While BPCL has already initiated discussions with SPC, the HPCL board has approved a proposal to explore picking up a stake in SPC. In addition to SPC, HPCL has also identified some other refineries, including Thailand’s only fully-integrated gas company PTT Plc, Petrom in Romania, Fujairah in UAE, a refinery in Nigeria and Caltex in Philippines for acquiring equity stakes. BPCL and SPC recently discussed acquiring partial stake in the Singapore oil major. In return, BPCL has offered SPC investment opportunities in its proposed refineries at Bina and Uttar Text Box: • In return for acquiring partial stake in SPC, BPCL may offer it investment opportunities in its proposed refineries
• Singapore lies on a key transit route for east (Asia) bound oil from Middle East. Makes sense to have a presence there
• National oil refiners are gearing up to form alliances with global biggies in line with India’s plan to become an export hub for petro products 

Pradesh. A proposal to trade crude and petroleum products with each other has also been made. Singapore’s strategic location at the entrance of the Malacca Straits is of great interest to India given that the country is a major oil transit route for east (Asia) bound oil and refined products from Middle East. With India’s recent initiatives towards becoming an export hub for petroleum products, leading national oil refiners, including IOC, BPCL and HPCL, are gearing up to form alliances with their global counterparts in jointly pursuing refining opportunities within the country and abroad.

HPCL in high-octane tie-ups with MNCs

 August 25, 2005. Hindustan Petroleum Corporation Ltd is discussing an array of joint investments with global oil majors, including Saudi Aramco and Total of France. The company has already moved a note among its board of directors to sign a memorandum of understanding (MoU) with Total for joint investments in India and abroad. HPCL has offered this participation in its grass roots refinery - a 9 mtpa project - in Bhatinda, Punjab, and in the expansion of its 7.5 mtpa refinery at Vizag in Andhra Pradesh. Marketing of petroleum products in India and abroad will also be part of HPCL’s discussions with these companies. HPCL may offer up to 50 per cent stake in its refinery projects that will be later hived off into separate entities. In lieu of stake offerings to global oil majors, HPCL is in turn looking for a commitment on assured crude oil supplies besides marketing of petroleum products from its refineries in global markets through the distribution networks of the foreign companies.

ONGC to sell kerosene to non-ration card holders

 August 25, 2005.The government has permitted ONGC to market their indigenously produced kerosene to non-PDS consumers after meeting in full, the demand requirement of oil marketing companies for the distribution of kerosene under PDS. This will be effective from August 2005.

RIL, Essar, Shell eye domestic ATF business

 August 24, 2005. Private oil companies Reliance Industries Ltd, Essar Oil and Shell India are planning to enter aviation turbine fuel (ATF) marketing, and have sought the government’s permission in this regard. So far, ATF marketing has been a monopoly of the state-owned oil companies like Indian Oil, Hindustan Petroleum, and Bharat Petroleum. Recently, ONGC received the ministry’s approval to market ATF in the country and had commissioned an ATF production cell at its Mangalore refinery. Reliance has already received the ministry’s nod for marketing ATF abroad and is presently exporting premier quality ATF to various countries. However, private oil companies including Reliance are facing difficulty in getting marketing rights of ATF here as this is a monopoly of oil PSUs,” sources close to Reliance said. Reliance has already submitted technical bids for setting up refueling stations at major airports of the country like Delhi, Kolkata and Mumbai amongst others, where the Airport Authority of India (AAI) wants to set up aviation fuel stations. Reliance has 3.6 million metric tonne per annum ATF production capacity at its Jamnagar refinery in Gujarat.

Transportation / Distribution / Trade

Stepping on the gas on Caspian oil

Text Box: • Russian and Caspian oil is mainly carried to the western markets through crowded Bosporous Strait
• A pipeline carrying oil from Russia and Caspian region to the Red Sea will bypass the Bosporous Strait
• The new corridor will enable buyers like India and China diversify their oil dependence on Middle-East
• Oil from Mediterranean Sea can be carried to a suitable port on the Red Sea and subsequently to India and China by oil tankers 

August 29, 2005. Petroleum minister Mani Shankar Aiyar’s plans to link oil and gas supplies from Russia and Caspian Sea to Asian markets is finally taking shape with GAIL (India) Limited proposing a joint working group with Botas of Turkey. The proposed group would conduct a feasibility study for laying an oil pipeline connecting Baku (a port in Azerbaijan) with Samsun (a port in northern Turkey) and Samsun with Ceyhan (a Mediterranean port in south Turkey). Botas is the national oil company of Turkey. GAIL has also proposed a gas pipeline from Samsun to Ceyhan where LNG facilities can be built for exports to European and Asian markets in China and India. The proposal was under consideration by Botas. GAIL has also expressed interest in participating in the offshore component of the gas pipeline connecting Caspian gas via Turkey to Greece and Italy. GAIL is keen on equity participation in the Turkish part of this pipeline. Botas has agreed to look at equity participation in the Turkish part of the pipeline as well as joint venture opportunities in the offshore pipeline consortium of Botas (Turkey), Depa (Greece) and Edison (Italy). Currently, Russian and Caspian oil is mainly carried to the western markets through the crowded Bosporous Strait. The idea to develop an alternative oil corridor from Central Asia to the Mediterranean Sea and then to the Red Sea was mooted by Mr Aiyar. A pipeline carrying oil supplies from Russia and Caspian (Black Sea) region to the Red Sea will not just help bypass the Bosporous Strait but this new corridor will also enable buyers like India and China to diversify their oil dependence on the Middle-East region. Oil from Ceyhan (Mediterranean Sea) can be carried to a suitable port on the Red Sea through either the on-land pipeline from Syria, Jordan, Egypt (Sinai) to the Red Sea or an offshore pipeline to enter Egypt (Sinai). From Red Sea, oil could be subsequently carried to India and China by oil tankers. The proposed Samsun-Ceyhan pipeline will follow the same right of way (ROW) as the Baku-Tilblisi-Ceyhan pipeline for almost 60 per cent of the route.

OVL top bidder for Nigeria deepwater block

August 26, 2005. ONGC Videsh Ltd. was the highest bidder for Nigeria's deepwater oil exploration block 323 with a bid of $310 mn (Rs 13.5 bn) and a promised investment of $525 mn (Rs 22.9 bn) at Nigeria's oil licensing bid round. Korea National Oil Corp. (KNOC) has preferential rights to take 65 percent of this block if it matches the winning bid, which would leave ONGC Videsh with a 25 percent interest after including a local Nigerian company with 10 percent as specified in the bid rules.

OVL to acquire stake in Cuba oilfields

 August 26, 2005. ONGC Videsh Ltd is in the process of acquiring 30 per cent stake in 10 oilfields in Cuba. The oilfields are being explored by Spanish oil major, Repsol YPF. OVL is also negotiating with the Cuban government to acquire 2 more oil fields in that country. OVL officials will accompany minister of state for external affairs Rao Inderjit Singh to Cuba for further negotiations. As on December 31, Repsol YPF held mining rights in Cuba on 6 offshore exploration blocks, with a total net surface area of 10,702 km. OVL has operations in 12 nations including Vietnam, Russia, Sudan and others.

Policy / Performance

Petroleum refiners eye exports

August 30, 2005. India’s surplus refining capacity is set to nearly double to 33.4 mt by the end of the next financial year and more than treble to 56 mt in 2011-12 from 17.5 mt at the end of 2004-05. The country’s refining capacity is projected to rise from 127 mt now to 154 mt in two years and 210 mt by 2012. At the same time, the demand is expected to touch 120.4 mt by the end of 2006-07, compared with the present level of 111.7 mt. Assuming a growth rate of 3.7 per cent observed during the last three years, the petroleum ministry has projected the demand at 144 mt at the end of 2011-12.  The only private sector refiner, Reliance Industries Ltd, which has around 25 per cent share in the country’s total refining capacity, plans to upgrade to 60 mt from 33 mt. Essar Oil is hoping to get its refinery going with a 12 mt capacity next year. By then, the public sector refiners are expected to add 26 mt. The public sector companies will invest about Rs 63,348 crore (Rs 633.48 bn) in refineries by 2011 for a capacity of 138 mt. The refiners are making these large investments with an eye on the ever-expanding global markets for petroleum products. AT Kearney, in a recent report, has said there is an unfulfilled demand of 115 mt for petroleum products in the international market, which presents an attractive opportunity for India. Of a total of 17.5 mt, the country exported 7 mt of diesel, 2.8 mt of petrol, 2.9 mt of naphtha, 2.4 mt of aviation turbine fuel and 1.8 mt of industrial fuels like furnace oil. The AT Kearney report also predicts stiff competition, especially from the existing refining hubs of West Asia and Singapore, and in large markets like China, for those who want to invest there. 

Oil price hike after Sept 6

 August 30, 2005. The expected hike in petroleum products is likely to be after September 6. The government would have to take a call soon since they cannot let the oil PSUs go into red in the second quarter too. While petrol prices were likely to be raised in the range of Rs 2-2.50 a litre, diesel prices might go up by Rs 2. The Cabinet would also have to decide on a hike in LPG prices. The hike was expected to be around Rs 10. The petroleum ministry had also asked for lowering customs duties on crude oil instead of petroleum products but this was rejected. Besides, the proposal to set up a price stabilisation fund through money coming from cess (collected under the Oil Industry Development Act (OIDA)) on crude oil was not likely to be accepted especially since large chunk of this fund was used for subsidising the fertiliser industry. Petrol is sold at Rs 3.63 a litre below the import parity price while diesel is under-priced by Rs 4.15 per litre. Cooking gas was being sold at a loss of Rs 92 per cylinder and Rs 11 was lost on the sale of every litre of kerosene. 

Kazakh not to support ONGC`s PetroKaz rebid

 August 29, 2005. The Kazakhstan government will not support a rebid by India’s Oil and Natural Gas Corp for acquiring PetroKazakhstan. The board of directors of PetroKazakhstan has already accepted offer made by China National Petroleum Corp Interenational (CNPCI). Though Kazakhstan does not have a pre-emption right, its approval is required for completing the deal. OVL tied up with an investment vehicle controlled by steel magnate, Lakshmi Mittal, to make a bid of $3.98 bn (Rs 175 bn) for Kazakhstan’s third largest oil producer. It claims that its bid was higher than CNPCI’s initial bid and the Chinese firm was “unfairly” allowed to revise its bid. ONGC was not given a similar opportunity.

India needs gas from Iran and Turkmenistan: PM

August 28, 2005. Highlighting India's energy requirements, Prime Minister Manmohan Singh said it would prefer to have gas pipelines from both Iran and Turkmenistan passing through Pakistan and Afghanistan. He said India's economy was growing at a rate of 7-8 per cent per annum. Therefore there is an enormous demand for unmet commercial energy, which is going to increase. Both the pipelines are currently at proposal stage. While India has short-listed three financial advisors including KPMG, Standard Chartered and Ernst & Young for suggesting project structure for executing the $7.4 bn (Rs 323 bn) Iran-Pakistan-India gas pipeline, Turkmenistan is currently assessing the gas reserve for export through the proposed pipeline of Turkmenistan-Afghanistan-Pakistan. This proposal is backed by Asian Development Bank but analysts are sceptical about the natural exportable gas reserves from Turkmenistan.

Special emphasis on oil exploration: Govt

 August 25, 2005. The outcome budget of the government lays special emphasis on enhancing existing oil production in the country. Setting aside a massive outlay of Rs 21,106.46 crore (Rs 211 bn) for 2005-06 towards undertaking exploration and production (E&P) activities, the government expects that there will be incremental reserve accretion of 49.95 million tonne of oil equivalent (mtoe) by new hydrocarbon finds as also by acquiring oil and gas equity abroad. The projects undertaken at this outlay include drilling of 149 exploratory wells, 188 development wells, besides opportunities to acquire new equity oil and gas fields abroad. On the refining front, in order to meet the demand of petroleum products, the refining and marketing companies along with their subsidiaries are undertaking projects to enhance refining capacity, besides upgrading fuels to the latest euro norms. With a outlay of Rs 6,163.23 crore (Rs 61.63 bn), these companies would simultaneously create additional pipelines and marketing facilities for future distribution of products. The deliverables would include expansion of Panipat refinery’s capacity by 6 mtpa, the petrol quality upgradation project of IOC at Mathura, Haldia, Kochi and Numaligarh, diesel quality upgradation by IOC at Panipat, Mathura and Kochi etc.

India petro products export hub: Aiyar

August 25, 2005. Petroleum minister Mani Shankar Aiyar said that his ministry would go ahead with building new refineries to make India a petroleum products export hub despite public sector oil firms losing heavily on fuels sales in the domestic market. He said that making India a global hub for exporting petroleum products the focus of the country this year would be on refining. Refinery margins in India are among the highest in the world and it should attract people to invest in creating more refining capacity, he said. The government will ensure that oil PSUs stick to their investment targets despite incurring huge losses on fuel sales. Refiners Indian Oil Corp, Hindustan Petroleum Corp and Bharat Petroleum Corp, which reported first ever net losses in Q1 of the current fiscal, have planned huge investments in capacity addition. IOC plans to invest Rs 18,000 crore (Rs 180 bn) in a new refinery-cum-petrochemical complex at Paradip in Orissa and expand its Panipat refinery capacity to 15 mt by 2008. BPCL is building a new refinery at Bina in Madhya Pradesh, while HPCL has plans for a 9 mt refinery at Bhatinda in Punjab. Also proposed is a refinery in Rajasthan.

Iran opposes IOC- CPC merger

August 25, 2005. The Iranian government representatives on the board of Chennai Petroleum Corporation (CPC) are against the merger of the company with its parent, Indian Oil Corporation (IOC), because their stake in a merged entity would be insignificant. The Iranian government’s arm Naftiran Intertrade Company currently holds a 15.4 equity stake in CPC.  IOC, which holds a 51.8 per cent stake in CPC, needs the consent of the Iranian shareholders to effect a merger. 

New petro pricing policy soon: Aiyar

 August 25, 2005. The government will unveil a new policy on pricing of petroleum products. Petroleum and Natural Gas Minister Mani Shankar Aiyar said the government would ensure that investment plans of oil marketing companies were not hit due to mounting losses caused by high crude oil prices. He said a new mechanism on the lines of New Exploration and Licensing Policy was required to attract foreign direct investment in the refining sector. Currently, Iranian National Oil Co has a 15 per cent stake in Chennai Petroleum Corp Ltd and Oman has a miniscule stake in Bharat Petroleum Corporation Limited’s proposed Bina refinery in Madhya Pradesh.

Fund mooted to shield LPG, kerosene users

 August 24, 2005. The petroleum ministry has moved a Cabinet note for setting up a price stabilisation fund for sensitive products like PDS kerosene and domestic LPG. Strongly recommending that LPG and kerosene subsidies be provided in a transparent manner through the budget, the ministry’s note has estimated an extra budgetary provision of about Rs 19,500 crore (Rs 195 bn). The note also stresses on the need for effective distribution of subsidies. It explains that along with a transparent policy, targeting subsidies is also of urgent significance. It also says that a system of distribution of domestic LPG through ration cards, along with free availability of sufficient quantities at market prices, for making the subsidies more targeted. This can bring down the subsidy amount considerably.

LNG shipping policy: govt steps on the gas

 August 24, 2005. Eager to bring about changes in the “restrictive” liquified natural gas (LNG) shipping policy, the energy coordination committee (ECC) set up by the Prime Minister has directed that the note on the relaxation of the policy is prepared by the commerce department expeditiously and placed before the Cabinet without undue delay. This follows Prime Minister Manmohan Singh’s announcement that the LNG shipping policy should change to give a wider choice of carriers to LNG purchasers. The current policy allows only Indian flag vessels or foreign vessels with minimum 26 per cent ownership by an Indian company to import LNG on f.o.b basis where the importer pays for freight and insurance. The PM had said that this clause should be removed to allow all vessels to import LNG. Currently, only Petronet LNG is shipping LNG since none of the Indian shipping companies own shipping vessels. A number of domestic companies, including the Shipping Corporation of India, Great Eastern Shipping, Essar Shipping and Varun Shipping Company, have reportedly shown interest in transportation of LNG. The shipping ministry argues that allowing foreign companies at this stage would expose Indian companies to stiff competition, which they may find difficult to withstand.

L&T may partner domestic oil giants for global bids

August 24, 2005. Engineering and construction major Larsen & Toubro (L&T) is seeking alliances with domestic oil and gas majors such as ONGC, IOC and GAIL India to bid for international projects. The company would approach ONGC and GAIL India very soon. It had a memorandum of understanding (MoU) with IOC and Engineers India long ago to work together outside the country. The initiative will give an impetus to L&T’s hydrocarbon division, which has a turnover of Rs 2,500-3,000 crore (Rs 25-30 bn). L&T has already started working on a consortium model. 



REL for thermal power project

August 30, 2005. Reliance Energy Ltd has started construction work on the two units of 300 MW each of the Deenbandhu Chhotu Ram Thermal Power Project in Yamunanagar. It is likely to spend Rs 2,396 crore (Rs 23.96 bn) on the construction of the project. The units are expected to be commissioned on November 20, 2007, and February 20, 2008 respectively. The new power project will supply 14.4 million units of power to Haryana. With the commissioning of new projects, the installed power generation capacity in the state would increase by 3,000-4,000 MW in the next three-four years. State government was exploring the possibilities of setting up a 1,050 MW gas-based power project at Jhajjar with the assistance of Tata Power Ltd.

MSEB plans more generating units

August 28, 2005. Maharashtra State Electricity Board may soon set up power plants with generating units having a capacity of 800 MW as against the current limit of 500 MW. Central Electricity Authority (CEA) is in process to prepare the ground for inducting 800MW units. These units could be more economical and efficient since the pollution level is lower. Maharashtra State Power Generation Company (Mahagenco) is likely to consider the induction of these new age power generators.

Nod for thermal power plant in Rajasthan

August 27, 2005. A coal-based power station with a capacity of 500 MW is to be set up in Baran district in Rajasthan. The State Government has given clearance to the Rajasthan State Vidyut Utpadan Nigam to set up two units of 250 MW each at Motipura village. Both the units of the plant would start production by December 2008 at the rate of Rs. 2.14 per unit.

KPCL to produce 3,000 MW power

 August 27, 2005. Karnataka Power Corporation (KPC) aims to produce an additional 3,000 MW of power in next five years. The state has a demand for 8,000 MW power and it was producing 4,000 MW at present. Additional power will be generated from Bellary Thermal Power stations at e Bellary, Raichur and Bidadi. Additional funds to the tune of Rs 9,000 crore (Rs 90 bn) will be released for the purpose. Measures to set up 10 new power stations, upgrade 100 stations and installation of new lines would be taken at a cost of Rs 15,000 crore (Rs 150 bn) in next five years. 

Transmission / Distribution / Trade

PSUs outperform pvt distribution utilities

August 27, 2005. The private sector may be setting efficiency benchmarks in most sectors. In power distribution, however, it is opposite. State-owned utilities of Andhra Pradesh, Rajasthan, Himachal Pradesh and Karnataka have outperformed by a wide margin compared to private distribution companies operating in Delhi and Orissa in terms of reducing aggregate commercial and technical (AT&C) losses during the last two years. High AT&C losses, which have been the main reason for near bankruptcy of distribution utilities in most States, is a measure of the units available for sale by a utility and the units realised by it. Leading the public sector brigade is Jaipur Vidyut Vitran Nigam Ltd (JVVNL), one of the companies formed after unbundling of the erstwhile Rajasthan Electricity Board, which has brought down AT&C losses by nearly 21 percentage points between 2001-02 and 2003-04. During the same period, the Himachal Pradesh State Electricity Board brought down AT&C by 20.10 percentage points and the progress made by the utility is significant with loss levels plummeting to below 9 per cent and, more importantly, this reduction happening on a comparatively lower base. Andhra Pradesh Northern Power Distribution Co Ltd (APNPDCL), one of the four state-owned utilities in Andhra Pradesh, has brought down losses by nearly 16 percentage points during the two-year period. The performance of private companies pales in comparison. Reliance Energy-controlled NESCO in Orissa is among the better performing private distribution utilities, having managed a loss reduction of 10.12 percentage points during the period. The performance of three private distribution utilities in Delhi, in terms of bringing down losses, has been around just 3 percentage points. This despite Delhi being a compact distribution zone with a primarily urban consumer profile and an efficiency loss reduction criterion being built into the privatisation pact. The data excludes the private companies operating in Mumbai. Also, the better performing state-owned utilities are the ones that have followed unbundling and corporatisation, with the unbundled utilities of Rajasthan, Andhra Pradesh and Karnataka doing much better in tackling losses than SEBs. The Himachal Pradesh SEB is a notable exception.

Policy / Performance

Core sector projects completed

August 30, 2005. One hundred and sixteen infrastructure projects in the Central sector were completed at a final cost of over Rs 42,370 crore (Rs 423.70 bn) between May 2004 to April 2005 against only 59 projects between May 2003 and April 2004. Of the projects completed, 12 projects in the coal sector and 11 in the power sector. In the petroleum sector, 5 projects were completed.

MP hikes power subsidies

 August 30, 2005. The Madhya Pradesh has decided to offer Rs 300-crore (Rs 3 bn) power subsidy to various categories of consumers, particularly those belonging to weaker sections of society. The consumers who consume up to 30 units a month will get power at Rs 1.75 per unit. A tariff of Rs 1.20 per unit has also been proposed for farmers against a power supply of up to 300 units per month on meter. The state decided to grant a subsidy to local self-governing bodies (municipal corporations, nagar panchayats, and gram panchayats) against power consumption for street lights. The government has also maintained a tariff of Rs 2 per unit to the powerloom sector and the available subsidy will stay.

105, 000 enjoy free power in Jharkhand: CBI

August 30, 2005. The Central Bureau of Investigation (CBI) has detected over 105, 000 domestic consumers who have not been paying for power for the last three years in the state of Jharkhand. Out of this, over 30,000 of such free-power consumers were residing in the state capital. The free-power consumers detected were all based in only 16 out of the 34 divisions serviced by the Jharkhand State Electricity Board (JSEB). The number of free-power consumers was likely to double if the figures from the remaining 18 divisions were taken into account after compilation. 

MoP taps performing utilities to improve PLF

August 29, 2005. The power ministry (MoP) has roped in performing utilities such as National Thermal Power Corporation (NTPC), Andhra Pradesh Generation Company (APGenco), Karnataka Power Company Ltd (KPCL) and Rajasthan Generation Company (RGenco) in a serious bid to improve plant load factor (PLF) and availability of power of 26 power stations across the country whose PLF is below 60 per cent. These companies would be associated in the "Partnership for Excellence" programme to be launched for those power stations situated in Uttar Pradesh, Jharkhand, West Bengal, Tamil Nadu, Assam and Madhya Pradesh with a total generation capacity of 9,833.5 MW. Some of these stations have PLF as low as 5.7 per cent (Barauni), Patratu (11 per cent), H'Ganj (18.7 per cent), Chandrapura (28.9 per cent), Santaldih (31.8 per cent), Tenughat (36 per cent). NTPC, with high operation availability of 91.2 per cent and PLF of 87.31 per cent, has been given the responsibility of 15 of the total 26 power stations situated in Bihar, Jharkhand, Uttar Pradesh and West Bengal. The balance 10 would be divided into other utilities. NTPC has agreed to carry out the assignment on cost basis and with clear cut understanding that profit will be neutral. The ministry has embarked upon short term, medium term and long term measures under the Partnership for Excellence programme. In the short term (below six months), power stations are expected to improve PLF by 10 per cent and it would not require any investment. During the medium term (upto one year), power stations with the help of NTPC and other agencies are expected to tone up their operation and maintenance, overhaul and replacement of auxiliary system with some marginal investment. The long-term measure (upto three years) envisages renovation and modernisation of power stations with PLF below 60 per cent or those, which have been closed down. The ministry has introduced a mechanism whereby a quarterly review would be made.

India invites Chinese investments in power sector

August 28, 2005. India has invited Chinese investments in the power sector, including transmission and high-end generation. Both sides will exchange views on tariff setting and regulatory issues and will also learn from experiences of each other in the sector.

Centre to stop funds to Delhi's discoms: Panel

August 27, 2005. The Parliamentary Standing Committee on Energy has asked the Union Government to exclude Delhi's private power distribution companies from access to cheap funds under Central schemes citing less than satisfactory use of the money. This comes in the wake of this year's 10 per cent tariff hike and lacklustre performance by the firms in tackling the technical and commercial losses in the Capital. These private distribution companies (discoms) have neither shown any tangible results even after using cheaper Government funds under the Accelerated Power Development and Reforms Programme (APDRP), nor these private players have passed on any benefit to consumers.

101 coal projects earmarked for Tenth Plan

August 25, 2005. The government has identified 101 new projects to be taken up during the Tenth Plan period to bridge the widening demand and supply gap in the coal sector. Out of this 22 projects were producing coal and 45 projects were slated for production during 2005-06 and 2006-07. The government was also seriously considering creating 71.3mt additional capacity in 16 mines of the Coal India Ltd (CIL). The total coal production during 2004-05 is estimated at 382.14 mt. The Plan panel has assessed that the total raw coal demand would be 445.65 mt for 2005-06 whereas its availability is estimated at 406.48mt, leaving a gap of 39.17mt. Meanwhile, the CIL has formulated a time-bound programme under which production would be increased by 20 mt during current fiscal to reach 343 mt.

India Inc’s power, fuel spend up in Q1

 August 25, 2005. The aggregate expenditure on power and fuel of 403 corporates increased by 10.28 per cent to Rs 6,291 crore (Rs 62.91 bn) during April-June 2005, from the level of Rs 5,704 crore (Rs 57.04 bn) during April-June 2004. On the other hand, the total expenditure of these companies increased by 11.2 per cent to Rs 33,497 crore (Rs 334.97 bn) during April-June 2005, from the level of Rs 30,115 crore (Rs 301.15 bn) during April-June 2004. So the share of power and fuel in total expenditure has marginally decreased from 18.94-18.78 per cent during the same period.

Investors urge for rebate for SEBs

 August 24, 2005. Investors and analysts raised several apprehensions that following the end of the rebate scheme after March 2006, the incentive to pay on time may not be there for state electricity boards (SEBs). Thus NTPC would have to take necessary action to continue timely payments by SEBs. With over 99 per cent of sales to SEBs, NTPC runs a “credit risk.” The 4 per cent rebate on interest payment on the one-time settlement (OTS) would end in March 2006 and repayment of these OTS bonds start in September next year. NTPC has been receiving 100 per cent monthly bills from SEBs after they entered into the tripartite agreement under which the outstanding dues of SEBs to NTPC as on September 30, 2001 were scrutinised and subsequent payments to NTPC were protected by recourse to the account of the state governments with the RBI. One of the reasons for the timely payment by SEBs to NTPC is that this enables them to get a 4 per cent rebate on 8.5 per cent coupon interest payment on OTS bonds which were issued against their past dues. Some experts indicated that any delay in the SEB payment would adversely affect NTPC’s ability to raise or refinance borrowings. NTPC’s monthly collection is over Rs 5,000 crore.





Iran’s oil production to hit 6m bpd by 2025

August 30, 2005.  Iran’s oil production would touch 6m bpd by 2025 according to OPEC’s quota. The production would gradually increase from 4.3m bpd in 2005 to 4.6m bpd by 2010.According to a report the worldwide per annum demand for oil and natural gas is expected to grow by %1.7 and %3.1 respectively. Furthermore, Iran’s gas production is going to be 206b cubic meters for 2005, and it would rise to 342b and 519b cubic meters by 2010 and 2025 in that order.

Also OPEC’s oil production is estimated to be at 50m bpd by 2020 and the organization would maintain to be the top energy supplier of the world while the world may experience its peak consumption in 2009. In the next 20 years, natural gas share of consumption would stand second to oil and coal use would find the 3rd place. Moreover, the oil production would be at 114.6m bpd by 2025, which will be almost 39m bpd more than the demand registered for 2000.

Russia for more investment in Italy’s energy sector

August 29, 2005. Russia wants its natural gas monopoly Gazprom to invest extra funds in Italy's energy sector, including its gas distributing networks, and is ready for reciprocal measures. Russia is ready to study the possibility of Italian investment in the Russian natural gas sector. Russian-German cooperation was a good example in that sphere.

S. Korean wins Nigerian oil rights

August 28, 2005.  A South Korean consortium won rights to develop a pair of oil fields off the coast of Nigeria. The two sites are estimated to contain 2 billion barrels of crude oil, 2.5 times more than South Korea's 2004 annual oil consumption of 800 million barrels. Africa's largest oil producer began awarding new petroleum-exploration rights. Early winners were Taiwan-based Chinese Petroleum Corporation, awarded an onshore field in the southern Niger Delta, and the local Northern Nigeria Development Company, which won rights to explore in two northeastern plots. The consortium beat competitors including Exxon Mobil Corp. and Royal Dutch Shell PLC. The fields, designated OPL 321 and OPL 323, are believed to hold 1 billion barrels of oil each.

Norsk Hydro discovers oil

August 25, 2005. Norsk Hydro ASA struck oil and natural gas with a North Sea exploration well that was close enough to an existing platform that production can begin this year. It was the second petroleum find announced this week by the Oslo-based company, and the fifth so far this year. The well was drilled near the company's Oseberg South find, which already produces 82,000 barrels of oil per day. The exploration well would be converted to a production well, and will begin to produce via Oseberg platforms by the end of the third quarter. The well was drilled by a floating rig to a total depth of 2,550 meters (8,366 feet), in water depths of 103 meters (338 feet). The find was about 130 kilometers (80 miles) northwest of Bergen, the main city on Norway's west coast.

Tullow Oil plc start production from Munro

August 25, 2005. Tullow Oil plc starts natural gas production from its Munro field development commenced on August 22, 2005 at an initial average rate of 55 mmscfd. This has been achieved six weeks ahead of the development schedule and only 16 months after the field was discovered. The Munro development, Tullow's second UK development in 2005, consists of a single well, a minimum-facilities platform and a 5km pipeline that connects to the Tullow-owned CMS III and CMS infrastructure. The Munro field, in which Tullow has a 15% interest, is expected to produce at a peak rate of 80 mmscfd.

Egypt seeks investments in oil and gas sector

August 28, 2005. The Egyptian government announced plans to lure $16 billion of new foreign investments in oil and gas projects in the next five years. Local investment in oil and gas is expected to amount to $4 billion for the same period. The Govt. urged the private sector to invest heavily in the oil and mineral resources sectors as the oil, gas and petrochemical industries are witnessing a steady growth at the present time.

Last month the Malaysian national oil company, Petroleum National Bhd (Petronas), announced a working plan to increase investment in oil field exploration and deepwater gas fields in the Mediterranean Sea, and to increase the Company's participation in liquefied natural gas projects. Agreement between the Egyptian Tharwa Oil Company, Egypt's first oil exploration investment company and Petronas to evaluate the potential of Egypt's oil fields and to propose new plans for further investment in the oil sector.

Russia ambitious to become oil superpower

August 27, 2005. Russia is reaping the economic benefits of sky-high world oil prices, but appears uncertain how to translate its energy riches into lasting international political influence. Russia's leaders seem in little doubt that, in an era of $60 a barrel oil, they command more attention on the world stage than at any time since the break-up of the Soviet Union abruptly denuded Moscow of its great power status.

In the 1970s and 1980s nuclear weapons are what gave the Soviet Union a position in the world. In this decade it's energy, which has given Russian an entree to the top table. With energy supplies tight, a growing number of countries have their eyes on Russia, the world's second largest oil producer and its biggest source of gas reserves, as a potential long-term supplier of hydrocarbons. It's interesting for Russia to be courted by so many countries. The United States is interested in liquefied natural gas, Europe in gas and China in oil. At times of high energy prices, oil exporters can be plagued by the dreaded "Dutch disease", when a flood of petrodollars pushes up the value of the local currency and drives increasingly uncompetitive manufacturers to the wall. A struggle between state gas behemoth Gazprom and state oil firm Rosneft for control of oil assets after the break-up of Yukos, formerly Russia's biggest oil company, is also a distraction for policymakers when they could be working on defining a broader oil strategy.

China, Venezuela firms to co-develop oilfields

August 27, 2005. State oil companies from China, the world's second-largest oil importer, and fifth-largest exporter Venezuela are strengthening their partnership by co-investing in oilfields in the South American country. China National Petroleum Corp (CNPC), the parent company of the nation's largest oil producer listed in Hong Kong, PetroChina, signed an initial agreement with Venezuela's state oil company, Petroleos de Venezuela SA, to develop and manage Venezuela's Zumano oilfields in the eastern part of the country.

The Zumano area has 400 million barrels of light and medium crude and 4 billion cubic feet of gas reserves. Venezuela plans to spend US$56 billion from 2006 to 2012 to double its oil production to 5.1 million barrels a day from the current 2.6 million barrels per day. They have also held preliminary discussions about creating a financing fund for building infrastructure in Venezuela based on oil trade. Further details were not available from either of the two companies.

Hunt Oil signs exploration contract in Namibia

August 23, 2005. Hunt Oil Company, through its wholly owned subsidiary Namibia Hunt Oil Company, signed a Petroleum Agreement with the Republic of Namibia. The agreement gives Hunt the right to carry out petroleum exploration and production operations in Luderitz Basin Offshore Area Namibia in partnership with NAMCOR, the state oil company. The agreement covers approximately 38,322 square kilometers (approximately 9,500,000 acres) in the Luderitz Basin Offshore Area. Namibia Hunt Oil Company is a wholly owned subsidiary of Hunt Oil Company, a privately held independent oil and gas firm based in Dallas, Texas, led by Ray L. Hunt.

Pak invited offshore drilling in Indus block

August 24, 2005. Ministry of Petroleum and Natural Resources (MPNR) has sought bids for granting petroleum exploration rights of an offshore block in Indus region. The ministry has floated an international tender recently to seek interest from parties for carrying exploration activities in the offshore Indus block. The technical identification is Block No.2466-2 in Zone-O. The parties will submit their bids to the ministry on September 19, 2005 after which MPNR would ascertain the best offer.

The ministry will award the contract of the block after evaluating the bids and sign a Petroleum Exploration and Concession Agreement.  The party that wins the contract will carry out surveys including seismic 2-D and 3-D to assess the presence of hydrocarbon contents in the blocks. The party will also drill an exploratory well during the initial three years term.

Based on geological prospects and available gas transmission infrastructure network, country was divided into three prospective zones. Wellhead prices were linked to 67.5 per cent, 72.5 per cent and 77.5 per cent of the price of a basket of imported crude oil for discovery in Zone III, II and I respectively. Under the Petroleum Policy 2001 (Current Policy), the formula of 2000 has been further improved by adding the ceiling price of $36/barrel on C&F basis.

Nigeria to put 78 oil blocs on offer

August 24, 2005. Oil-rich Nigeria will this week put 78 oil blocs on offer to interested local and foreign investors. It is expected that all the blocs on offer will be auctioned live on Aug. 26. However any blocs not sold on Aug. 26 shall be put forward for a second round of auction on Aug. 27.  A 379 local and foreign firms have signified interests in the potentially-lucrative blocs which include 15 in deep water, six each in continental shelve and onshore, 16 in Chad Basin, nine in Anambra Basin, 12 in Benue Basin while 14 blocs have been reserved for strategic partners. The reserved price for the blocs ranged between $500,000 and $50 million.

GE makes first offshore natural gas investment

August 23, 2005. General Electric Co. is expanding its natural gas business by going offshore. GE, which has invested in onshore oil and gas for more than a decade, it will invest more than $100 million in a limited partnership with Houston-based F-W Oil Exploration LLC to produce natural gas in the Gulf of Mexico. GE also plans to finance the completion of a 48-mile pipeline system to transport 30 million cubic feet of gas per day from F-W's fields in the South Padre Island area 12 miles offshore of Texas.

Through partnerships, GE's energy financial services unit owns $1.5 billion in oil and gas reserves, producing more than 140 million cubic feet of natural gas and 31,000 barrels of oil per day.


Sudan and Petronas sign for new refinery

August 29, 2005. Sudan and Malaysia's Petronas signed a contract worth about $1 billion to build a new 100,000 barrel-per-day refinery in the coastal city of Port Sudan. 

Brazil refinery to be operational by 2011

August 29, 2005. A new multibillion dollar refinery in Brazil that will process crude oil from Venezuela and Brazil should be up and running by the end of 2010 or in early 2011. However, no decision has been made yet on the exact location of the refinery. The refinery will process about 150,000 barrels of crude oil daily and will cost between US$2 billion (euro1.6 billion) and US$2.5 billion (euro2 billion) to build. The project will be a joint venture with Venezuela's state-oil company, Petroleos de Venezuela SA.

CNOOC to build a $2.0b refinery in southern China

August 28, 2005. A leading Chinese oil company has entered a deal with a top Australian engineering firm to build a 17 billion yuan (two billion dollar) oil refinery in southern Guangdong province. China National Overseas Oil Corporation (CNOOC) would build the refinery in Huizhou city in a move that should help alleviate oil shortages in Guangdong, China's leading industrial powerhouse. It would be CNOOC's first foray into the refining business. The company has largely been engaged in offshore and onshore oil exploration and extraction.

Transportation / Trade

Repsol extension to Argentine gas pipeline

August 30, 2005. Spain's biggest oil company expanded the capacity of its Argentine natural-gas network with opening of a $210 million extension to the South American country's Gasoducto Norte pipeline. Madrid-based Repsol invested $100 million in the project. Other investors included Transportadora de Gas del Norte, which managed the expansion project, and Brazil's state development bank. The 234-kilometer (145-mile) extension will boost capacity by 1.8 million cubic meters a day. The 3,336- kilometer Gasoducto Norte pipeline serves the Argentine provinces of Salta, Tucuman and Cordoba and has an overall daily capacity of 22.6 million cubic square meters.

China exports crude shipments to US

August 25, 2005.  Despite a growing reliance on foreign crude, China has pumped up its small volume of crude oil exports this year due to rising offshore joint-venture production, with shipments to the United States more than doubling over last year. In the first seven months of this year, more than 20,000 barrels per day (bpd) of Chinese crude sailed for the U.S., 118 percent more than in the same period of 2004. While this is a paltry 0.2 percent of total U.S. imports, it was enough to make China the second-biggest exporter from all of Asia-Pacific, behind Vietnam but ahead of big producers such as Malaysia and Indonesia. The growing exports of Chinese crude underscore the fact that most oil flows freely in the global marketplace, seeking the best price no matter who owns the reserves. But this has not stopped Chinese policy-makers from seeking upstream assets to ensure supply security or soothed U.S. worries about Beijing's growing economic clout.

Canada’s Pembina to build pipeline

August 23, 2005. Pembina Pipeline Income Fund has signed a deal to build a C$290 million ($242 million) pipeline expansion to ship crude from Canadian Natural Resources Ltd. Under the agreement, Pembina will expand its Alberta Oil Sands Pipeline by adding a northern extension and building two loops, giving Canadian Natural exclusive access to transport service for the C$10.8 billion oil sands venture. Synthetic oil from the Syncrude project, now shipped on AOSP, will still flow in other dedicated lines on the system. The development is slated to start shipping 110,000 barrels a day in 2008, increasing to 232,000 barrels a day in 2012. Construction on the pipeline is slated to start in early 2006. Once the project is completed, Pembina will operate pipelines with capacity to move 640,000 barrels a day of synthetic crude from the oil sands.

CB&I to build liquefied gas tanks

August 23, 2005. CB&I has won a $100 million contract to design and build storage tanks at a Canadian liquefied natural gas terminal to be owned and operated by Anadarko Petroleum Corp. The terminal, near Port Hawkesbury on Cape Breton in Nova Scotia, will have an annual capacity of 7.5 million tons and a sendout capacity of 1 billion cubic feet per day. The first deliveries through the terminal are set for late 2008. CB&I said the contract covered the construction of two 180,000 cubic meter storage tanks. The company said it has already started engineering and procurement work.

Abu Dhabi's IPIC buys refineries in Far East

August 24, 2005. Abu Dhabi oil investment fund IPIC laid out plans to boost its exposure to Far East growth markets by snapping up refiners, buying into Taiwan firm CPC and possibly bidding for Royal Dutch Shell's LPG business. IPIC also wanted to double its stake in Spanish oil firm Cepsa to more than 15 per cent by buying stock from bank Santander. IPIC is not the only investment firm looking at opportunities in the region. British investment firm 3i Group Plc was keen on buying energy companies in Southeast Asia. IPIC wants to purchase up to 25 per cent of state-owned Chinese Petroleum Corp (CPC) of Taiwan and to almost double its stake in Spain's Cepsa to more than 15 per cent. Negotiations on both deals have been held up, however. IPIC signed a memorandum of understanding with CPC in June giving it the right to buy 20-25 per cent of CPC and set up a petrochemical joint venture with the Taiwanese firm.

Jordan turns fuel exporter

August 24, 2005. Jordan, normally a fuel oil importer, turned exporter with an offer to sell up to 300,000 tonnes a year of excess supplies after converting to natural gas for power generation. The extra 20,000-30,000 tonnes per month of straight-run fuel oil will add to the 400,000-500,000 tonnes a month of supplies now sold primarily by Russia, Iran and South Korea to small "teapot" refiners in China for cracking into other fuels. The Jordan Petroleum Refinery Co Ltd, which has a 100,000 barrel-per-day (bpd) refinery in Zarqa, it would have 200,000-300,000 tonnes of straight-run 800-centistoke fuel oil per year available for loading from the refiner's Aqaba terminal on a free-on-board (FOB) basis. After the introduction and use of natural gas for power generation in Jordan, it is projected that Jordan Petroleum Refinery will have surplus high-sulphur fuel oil available for export estimated between 200,000-300,000 tonnes per year. The new Jordan exports, for which no start date was specified, will add pressure to a market heavily dependent on demand from China, where many small refiners have scaled back operations due to thin profit margins.

Jamaica to buy cheap oil from Venezuela

August 24, 2005. Jamaica became the first Caribbean nation to finalize an agreement with Venezuela on a new plan for the South American nation to supply oil to countries throughout the region under below-market terms. Venezuela and Jamaica see themselves as a counterweight to U.S. influence in the region, even as Venezuela supplies 1.3 million barrels of oil a day to the United States - 8 percent of the total supply. Under the agreement with Jamaica, Venezuela will provide oil at a discounted rate of $40 per barrel, compared to the more than $60 that it now costs on the world market. The deal, which takes effect on June 29, will initially involve about 22,000 barrels per day. Jamaica will be able to pay Venezuela in goods and services as well as through low interest, long-term loans.

Policy / Performance

Russia to raise oil export duty from October 1

August 29, 2005. Russia will raise its export oil duty to a record high of $179 per metric ton beginning October 1.  The government reviews oil export duties every two months based on the average price of Russia's Urals crude on the world market in the previous two-month period. Today the export oil duty established from August 1 is $140 per metric ton. The October 1 increase is based on the July-August Urals price. After the export duty on oil is raised to $179 on October 1, the export duty on light petroleum products will be about $133 per ton and the export duty on heavy petroleum products will stand at about $71.6 per ton.The government commission for foreign trade protectionist measures will decide on a new oil export duty by polling and the related resolution will be published by September 20 and come into effect October 1.

METI, firms to develop gas-to-liquid as alternative fuel

August 29, 2005. A group of domestic companies including Nippon Oil Corp. will work with the Ministry of Economy, Trade and Industry to make gas-to-liquid a commercially viable overseas business by 2011. Gas-to-liquid, or GTL, is created by converting natural gas into a liquid form. It is seen as a promising alternative to petroleum, which has become less attractive due to high crude oil prices and tighter environmental regulations. GTL is also more efficient than petroleum-derived fuels and contains virtually no sulfur compounds. It is especially promising as an alternative to diesel fuel.

Japan Oil, Gas and Metals National Corporation, known as JOGMEC, Nippon Steel Corp., Inpex Corp., Japan Petroleum Exploration Co, Cosmo Oil Co., and Chiyoda Corp. are also expected to participate in the effort. Nippon Steel, JOGMEC and others are working on GTL technology that can make the fuel without removing the excess carbon dioxide contained in natural gas. They will build in Japan a proof-of-concept plant beginning next fiscal year. Currently, GTL is expensive to make. But if a technology for manufacturing GTL that eliminates the need for CO2 removal equipment can be developed, the cost of making the fuel would be lower, and it might be more economical if crude oil prices stay high. In addition, if Indonesian natural gas, which contains a large amount of carbon dioxide, can be made into liquid fuel, it could become an important energy resource for the Asian region. METI estimates that developing the business will cost 36 billion yen (US$326 million), of which 24 billion yen would be borne by the government. It plans to ask for 1.8 billion yen for the effort in the fiscal 2006 budget.

Indonesia fuel prices may rise

August 29, 2005. Indonesia will raise fuel prices early next year to reduce the impact of soaring global oil costs on its budget. Indonesia's economic recovery is being threatened by the impact of global crude oil prices at more than $60 a barrel, dwindling domestic oil output, and strong local demand for energy. Fuel subsidies cost the government around $7.4 billion in 2004, or 3pc of gross domestic product. Indonesia hiked prices by nearly 30pc in March to reduce pressure on the budget. Another rise would likely spark anti-government protests among the country's 210 million people.

Apache signs Australian gas contract

August 24, 2005. Apache Corporation has signed a new contract to supply gas to a major West Australian power station to be built at Kwinana, south of Perth. The gas will be supplied from the John Brookes field, jointly owned by Apache (55%) and Santos (45%). The 15-year term of the contract with the plant's developers, Wambo Power Ventures, calls for the delivery of approximately 215 billion cubic feet of natural gas (118 Bcf net to Apache) at a daily rate of 39 million cubic feet (21 MMcf net). The term can be extended an additional 10 years by mutual agreement. The second half of 2008 expects first gas delivery.  Apache Corporation is a large oil and gas independent with core operations in the United States, Canada, Australia, Egypt and the United Kingdom sector of the North Sea.



Three power plants being sought from UAE

August 30, 2005. The United Arab Emirates government will be shortly approached to ensure an early delivery of 320 MW power plants, which were gifted, to Pakistan some time back. Earlier this month, the federal minister had announced that installation of at least three power plants capable of generating over 730 MW on a daily basis would begin next year.

Three more power plants proposed – B’desh

August 29, 2005. To meet the huge-demand of electricity in the country, the BPDB yesterday incorporated three new small power plant proposal of power division. The power ministry asked the BPDB to increase the number of small power plants. Accordingly the BPDB proposed the areas at Moulovibazar, Sirajgonj and Kishoreganj. Aiming to add 530 MW power to the national grid by August next year, the Prime Minister's Office earlier, identified some 23 areas where power plants would be set up by the end of the fiscal year. Under the newly approved 10-50 MW power plant policy guidelines, private entrepreneurs will be able to set up power units with generation capacity between 10 megawatt (MW) and 50 MW.

Russia to build hydropower plant in Tajikistan

August 25, 2005. Russian holding company Bazovy Element signed a memorandum on the construction of a hydropower plant and an aluminum plant in Tajikistan. The project to build the Ragunskaya hydropower plant would require about $1.2 billion, and the reconstruction of the old aluminum plant and construction of a new one, about $600 million.

Datang to build 3 coastal power plants in China

August 25, 2005. Datang International Power Generation Co Ltd, the second-largest electricity producer in China, has received government approval to build three power plants in the coastal region and obtained a 28-per-cent stake in a coalmine to secure supplies for the plants. Three joint ventures will be set up with Datang International holding a majority stake and the rest controlled by local energy and investment companies. The plants will involve a combined investment of 21 billion yuan (US$2.6 billion) and have a total installed capacity of some 4,800 MW.

Transmission / Distribution / Trade

Calif. utility regulators eye power market plan

August 25, 2005. California utility regulators took a step toward revamping the state's power market to improve reliability of the electric system and encourage energy companies to build more power plants. The California Public Utilities Commission issued a "white paper" drafted by its energy division staff that lays out plans to set up a "capacity market" to ensure adequate power supplies are available and generators are compensated for their production. Uncertainty about state and federal plans to strengthen California's electricity market has kept many energy developers on the sidelines while demand for electricity grows, especially in the southern half of the state. California has been wrestling with new approaches to rebuild its electricity market after the debacle of the 2000-2001 energy crises.

ATC to build new transmission line

August 23, 2005. The Public Service Commission declared American Transmission Co.’s application for approval to construct a new transmission line from Waterloo to Jefferson complete. This decision marks the beginning of the regulatory review process, which will include engineering and environmental scrutiny and a public hearing. ATC is proposing to construct approximately 17 miles of new 138-kilovolt-transmission line to connect the Stony Brook Substation located in the town of Waterloo with the Jefferson Substation located outside the city of Jefferson. The estimated cost of the project is $16 million and may vary depending upon which route the PSC selects. The line is expected to be in service in mid-2008.

Policy / Performance

ACCI urges nuclear power rethink

August 29, 2005. Australia's largest business organisation has called on the Federal Government to seriously consider nuclear power, as a way of meeting Australia's energy needs. Australian Chamber of Commerce and Industry (ACCI) say solar and wind power are not yet viable solutions and would cost jobs if implemented in a widespread way. On the other hand nuclear power is economically efficient and does not add to greenhouse gas emissions.

The ACCI wants the Federal Government to conduct a feasibility study into the establishment of nuclear power generators in Australia. It concedes fossil fuels will continue to supply most of the country's energy needs but argues it is only sensible to look at all options.

Iran to become electricity hub for bordering countries

August 29, 2005. Iran is currently exchanging electricity with seven bordering neighbors namely Turkey, Iraq, Turkmenistan, Armenia, Pakistan, Afghanistan and Azerbaijan. The power trade market is of great importance due to 9% increase per year in domestic electricity consumption in the recent years. On the other hand it is beneficial for all when power is on high or low demand depending on the season. The total value of the equipments used in the industry is over $30b. The actual production capacity is currently 40,000 MW and this is yet to increase by 4,000 MW annually to fulfill the demand of domestic consumption. Establishing an atmosphere of true presence for private sector would increase the mutual and multiple trades of electricity exchange and swap, thus allowing the country, due to its geographical location, to be the main hub in this beneficial business.

Pak power projects feasibility reports on progress

August 28, 2005. A comprehensive plan is under consideration to harness the natural resources in order to generate electricity in Northern Areas. The government is spending Rs12.9 million on preparation of feasibility reports of five hydropower projects to generate 33 MW electricity in Northern Areas to over come power shortage. The projects are 20MW Hanzal power plant, 3MW Sai Jaglote plant, 3MW Kargah plant, 3MW Misgar plant and 4MW Minapin plant in Nagar.

Northeastern US plan to cut GHG emissions

August 24, 2005. Nine Northeastern U.S. states have reached a preliminary agreement to cap and then cut greenhouse gas emissions from power plants by 10 percent by 2020. The Bush administration has refused to sign the Kyoto Protocol, a greenhouse gas reduction plan that has been adopted by more than 150 other countries. The proposal, as it is currently written, caps emissions of carbon dioxide at 150 million tons a year starting in 2009. Under the proposed guidelines, emission reductions would be required starting in 2015, which would ramp up to a 10 percent cut in 2020.

Renewable Energy Trends



Reliance big plans for wind, solar power

August 30, 2005. Reliance Infocomm is planning to tap alternative sources of energy — wind and solar power — in an attempt to tide over power outages and ensure uninterrupted power supply for its network. It has completed the test phases of the alternative power projects near Dugrapur in West Bengal and intends to install them at other locations across the country. The company intends to set up solar panels and wind turbines across those circles where power failures are frequent. At present, Reliance Infocomm uses diesel generators on an average of eight hours a day during power grid outages. This will also be beneficial for the company as it is expanding its network to cover 5,700 towns and cities and four lakh villages in the country. It had set up its solar power pilot projects at Kunustara and Murugathal near Durgapur and used it to power the company’s repeater sites. The units generate 1.8 KW of power each during peak sunshine hours, of which the repeater sites consume up to 0.5 KW each. The remaining 1.3 KW are stored in batteries and used to power the network at bad sunlight hours, and during the night. The company has also installed its wind turbines at Kunustara and Murugathal on an experimental basis. The units have been installed to generate additional power, particularly during monsoons and when sunlight is scarce.

Rlys to focus more on jatropha plantation

August 28, 2005. The Railways plans to increase focus on plantation of `Jatropha Curcas'. In the Northern Railway, diesel locomotives currently are successfully running with Jatropha oil-blended diesel and this experiment would be extended in a big way to other zonal railways. The Railways has planted 7.5 million `jatropha' plants so far and will intensify this in the near future. The Railways has reached an agreement with Indian Oil Corporation (IOC) to provide 500 hectares of railway land for jatropha plantation and out of which, 180 hectares have already been provided to IOC for this purpose.

Emami diversifying into jatropha cultivation

August 26, 2005. FMCG Company Emami Ltd is diversifying into the cultivation and extraction of the biofuel jatropha. The West Bengal Government has already offered 300 acres of land to the company in Birbhum district. Emami has also entered into a technical tie-up with IIT, Kharagpur. It would start a trial project on 50 acres. The company would be investing approximately Rs 50 crore (Rs 500 mn) in this project.

Ammana Bio sets up ethanol unit

August 26, 2005. Ethanol supplier Ammana Bio Pharma Ltd has set up what it claims to be the country's first unit to derive ethanol from the grain crop sorghum (Sorghum bicolour), the sweet variety of which is used mainly as livestock fodder. The total investment in the project was Rs 20 crore (Rs 200 mn). It is expected to generate revenues of Rs 6 crore (Rs 60 mn) a year. Ethanol will help conserve precious foreign exchange for the import of crude oil by 5 to 10 per cent. The huge demand-supply gap has forced firms to look for innovative methods of producing ethanol. Sweet sorghum, unlike sugarcane, can be harvested in 100 days compared to the first cut of sugarcane, which requires 11 months. The company, which supplies ethanol to majors such as IOC, BPCL, RIL, HPCL, Ranbaxy, UB and McDowell, said the new unit would be self-supported with co-generation by using captive bagasse and press mud for achieving zero discharge of effluent. The company also planned to sell carbon credits since the unit qualifies under the clean development mechanism. Sweet sorghum is sown with seed and just 7.5 kg is enough for a hectare of land. Sugarcane is propagated from stem cuttings, and about 1,600 kg of cuttings are required per hectare. With a potential to make 7,000 litres of ethanol per hectare, sweet sorghum has high potential.

Alternative power source for 25,000 villages by 2012: MNES

 August 25, 2005. The ministry of non-conventional energy sources will give priority to the market penetration of alternate fuel systems and provide grid quality power to 25,000 villages by 2012. Apart from market penetration of alternate fuel systems and devices for stationary, portable and transport applications, the ministry would also work towards meeting rural energy needs through bio-energy. Its priority will be to deploy renewable energy systems and devices for commercial and urban use. Also, it will work towards providing grid-interactive renewable electricity that could replace coal. The ministry would strive to add 200,000 MW of generation capacity from renewable sources by 2050. The challenge was to reduce costs and increase the quality and reliability of renewable power before it could compete with the power generated from conventional sources.

Germany to buy carbon credits from TTD solar kitchen

August 24, 2005. In its efforts to reduce green house gas (GHG) emission, the German Government is in the process of buying carbon credits from the solar kitchen of Tirumala Tirupati Devasthanam (TTD). It has identified the TTD kitchen as one of the projects from which it would buy certified carbon reductions (CERs). The agreement would be signed within two months. GTZ (German Technical Corporation) has been commissioned by the German Government to identify CDM project in large solar-powered community kitchens in India. Eleven such projects that include community kitchen concepts backed by solar cooking at places such as temples, ashrams, hospitals, technical institutes and colleges are being considered from which CERs could be bought. It is also identifying community solar cooking projects that serve between 500 to 15,000 people per day. The solar kitchen has been installed at TTD by Gadhia Solar Energy Systems, a Gujarat based company. The solar steam kitchen installed in Tirupati Devasthanam can cook 15,000 meals at a time and can serve 30,000 meals per day (at two cooked meals per day). The rates per CER (each CER stands for one tonne equivalent of carbon dioxide reduced and can be traded globally) have not been decided as of now, but it is going to be "quite good" since the projects is Gold Standard. Gold Standard projects are those which, apart from reducing carbon dioxide emissions also result in community development, poverty alleviation and employment generation, among others. They are sought by buyers seeking "high quality certificates" and translate into less risk for investors. Meanwhile, a host country approval has been sought for the project from the Environment Ministry in India. After the host country approval, the project would seek registration at United Nations Framework Convention on Climate Change (UNFCCC).

TNPL plans to expand wind farm capacity

August 24, 2005. Tamil Nadu Newsprint and Papers Ltd (TNPL) is expanding its wind farm capacity, which has been a significant revenue source for the company. It is looking at adding 5 MW of wind farm capacity. It will set up three or four 1.25 MW turbines. TNPL operates a 2.30-lakh-tonne paper mill, which it is now upgrading at a cost of Rs 565 crore (Rs 5.65 bn) through a Mill Development Plan. The expansion to the wind farm would mean an investment of up to Rs 20 crore (Rs 200 mn) as each megawatt of wind power capacity costs up to Rs 5 crore (Rs 50 mn). This will be in addition to its existing capacity of 21.75 MW wind farm at Devarkulam and Muppandal in South Tamil Nadu. TNPL exports to the State grid the entire power generated from its wind farms.

Maharashtra for new non-conventional energy policy

August 24, 2005. The Maharashtra Government announced its new policy for non-conventional energy. Under the policy Jatropha plant from which bio-diesel is produced would be promoted on a large scale and its cultivation would be encouraged in the State. The country's first bio-fuel park would be also be set up in the state as a means to further promote non-conventional energy sources. Fallow land in tribal regions would be utilised for wind energy projects. However, the land titles and their land rights would remain with the tribals. Under the policy, land would be made available for non-conventional energy projects at low rates. The State was the first to have an independent ministry for non-conventional energy. Budgetary allocation to the tune of 15 per cent would be made for non-conventional energy projects in all municipalities. Under the policy, cooperative banks would extend soft loans for buying equipment for non-conventional energy projects.

100,000 hectares of wasteland to be devoped in AP

 August 25, 2005. The Andhra Pradesh government has come up with a plan to develop over 100, 000 hectares of wasteland for raising biodiesel, biofuel plantations and also plantations required for paper industry. The project will be undertaken by the Andhra Pradesh Forest Development Corporation (APFDC). The government has already issued instructions to 22 districts to identify and transfer 5,000 hectares of wasteland each in their respective districts with blocks having a minimum size of 50 hectares to APFDC. The steps required for the improvement of soil and moisture content including land levelling would be funded by banks under 100 per cent refinancing scheme of the National Bank for Agriculture and Rural Development (Nabard), which is available at low rates of interest of around 5 per cent. The APFDC is expected to tie up with biodiesel companies, biomass power units and paper mills for the supply of the seed and wood for their respective requirements. Identified types of plantations and species will be grown in suitable soils and areas. So far, over 30,000 hectares of land has been identified for this purpose from various districts. The APFDC is in the process of verifying the suitability of these lands for growing commercial plantations.


Panda to build fuel ethanol plant in Colorado

August 24, 2005. Panda Energy, a division of The Panda Group, will build a 100 million gallon per year renewable fuel ethanol plant in Yuma, Colorado. The $120 million facility will refine American grown corn into a clean burning auto fuel. The ethanol produced at the Colorado plant will be blended with gasoline and replace the equivalent of 2.4 million barrels of imported gasoline each year. The Yuma project is the second of five 100 million gallon per year fuel ethanol plants Panda will announce this year. In May, Panda announced it would build a 100 million gallon per year fuel ethanol plant in Hereford, Texas. To produce steam, both the Yuma and Hereford facilities will utilize a renewable fuel technology that converts a billion pounds of cattle manure each year into biogas fuel. Each facility will save the equivalent of 1,000 barrels of oil per day, which will make these facilities the most energy efficient ethanol refineries in the United States.U.S recently signed the Energy Policy Act of 2005, which expands the U.S. government mandate for increased ethanol use in blended gasoline to 7.5 billion gallons by 2012. This new expanded Renewable Fuel Standard alone will reduce America's dependence on foreign oil by 5%. The U.S. fuel ethanol production in 2004 was 3.4 billion gallons. The U.S. uses 140 billion gallons of gasoline per year.



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