Reciprocity in Energy Security Part - II

 (Excerpts from Asia-Middle East Dialogue (AMED) Working Group on political Security Issues – Majid A. Al-Moneef,Saudi Governor in OPEC Board)

Energy Security in the Asian Context:

rom an energy resource perspective, Asia is well endowed, with 70 and 44 per cent of world’s proven oil and gas reserves respectively. Asia’s production and consumption of oil constitute 40 and 34 per cent of world’s total while that of gas is at 21 per cent each which means that Asia in general is a net oil exporter of oil and almost self sufficient in gas. Its higher shares of global oil and gas reserves compared to its production and consumption shares means that it is more secure when it comes to hydrocarbon resources than commonly believed. It is the distinction between East and West Asia in oil and gas reserves as well as consumption and production patterns, and the projected increase in inter-Asia oil and gas trade which invites the issue of energy security. Since oil plays a central role in the producer and consumer countries economics, and in view of the projected increase in its demand and exports, the stability of its market is vital to the health of the economies of the producers, and more so far the Middle East oil exporters, due to the sheer size of the oil economy and the role of oil export revenues in the fiscal budgets and the balance of payments. 

There, the role of oil in the energy mix and of its imports to the consuming / importing countries economics and hence to their growth and prosperity is matched by its role in the economic development and industrializations of the producing / exporting countries. While the consuming countries are concerned about the availability of supply the producing countries have equal concern about access to markets and the overall stability of oil markets. Saudi Arabia on its part realizes the importance of market stability as a cornerstone to energy security from the demand and supply side. Realizing its dominant position in world oil in its economy, it has been working with the other producers to ensure that markets are adequately supplied at all times. It has built and maintained a production capacity of 11 mbd with excess capacity today at around 1.5 mbd, to cushion against unwarranted price fluctuations or supply shortfalls and to ensure supply reliability. Market related oil pricing by Saudi Arabia and other producers through the price formulas in the major markets help in ensuring transparency and enhancing security, so is their investment in refining and marketing in the main consuming markets with long term supply commitments to such markets. Saudi Arabia is now committing more than one million barrels per day of its crude exports to its joint ventures in U.S., Greece, Korea, Philippines and Japan and is planning other refining investments in China and India.

Therefore if energy security is not narrowly defined and its scope is expanded beyond supply to include demand issues as well, then energy security would not be only a consumer’s but also a producer’s concern. In the Asian context, the proximity of the Middle East to East Asia makes them natural trading partners. Increasing Asia Pacific oil imports from the Middle East in the past three decades did not undermine its remarkable economic performance over the period nor did it make the region less secure than Europe or North America. Alternatively, the fact that more than half the merchandise imports of the Middle East comes from its neighboring East Asia did not make the former vulnerable. In an era of globalization, the world economies are interdependent and the law of comparative advantages prevails. Middle East endowment with oil and gas resources makes it the natural provider of these resources and their derived products to the world and more so to Asia Pacific. The Middle East countries are planning investments to increase production capacities in response to the projected increase in world oil demand for their oil. The bulk of this investment is from Saudi Arabia, which is undergoing plans of 2.4 mbd capacity additions to be completed gradually by 2008 with a net capacity increment of 1.5 mbd. This is a costly investment to bring more oil the world markets and especially in Asia. It is estimated that total investment needed to increase production in capacities in OPEC to satisfy global oil demand in the reference case is $95 billion by 2010 (for a 38 mbd projected OPEC production) and $382 billion by 2025 (for a 51 mbd projected production) with the bulk of this investments coming from the Middle East. In case of a low world economic growth scenario the figures are $70 bn (32 mbd production) and $258 billion (42 mbd production) respectively. This uncertainty puts the difference of cumulative investment at $25 billion by 2010 and $125 billion by 2025 and highlights the importance of bridging this huge gap through dialogue to enhance understanding and appreciation among the concerned parties in the overall energy chain: producing and consuming governments as well as the energy industry. A normal growth in demand at stable prices is an objective of the oil producing / exporting countries while the availability and reliability of supplies at reasonable prices is the main objective of the consumer / importing countries. There is reciprocity in these objectives, whereby, the growth in demand at stable prices would increase investment outlays to increase production capacities and make supplies available to the consumers. This reciprocal security should be a major element of the global dialogue between energy producers and consumers exemplified in the international Energy Forum, which Saudi Arabia is proud to host its secretariat in Riyadh. It should also be a major element of the Asia-Middle East dialogue.

Concluded

Russia and Eastern Europe: Energy Aspect

(Sergei Kolchin for RIA Novosti)

he negotiations in the course of Russian President Vladimir Putin's recent visits to Hungary and the Czech Republic almost centered on oil and gas cooperation. This is not surprising, with Russia remaining the key energy supplier to Eastern Europe and Russian companies stepping up activities on the region's energy markets. The current relations in the oil and gas sectors between Russia and Eastern Europe are far from simple, mostly due to overlaps of the previous period of shared history. Meanwhile, the existing economic contacts push both parties to mutually beneficial solutions to pricing, transportation routes and property relations.

Eastern Europe receives oil and gas through common pipelines, such as the Druzhba oil pipeline and the Soyuz gas pipeline dating back to the socialist era. However, Russia established market relations with its partners in Eastern Europe long ago, in particular, in trade they have switched to world prices. Eastern Europe too has changed its attitude to its energy dependence on Russia. The country is no longer seen as a guarantee of a steady economic growth. Moreover, Eastern Europe has been seeking a way out of the dependence through contacts with the EU and alternative suppliers of oil and gas. The ambition has mostly political, not economic, roots, but it is unbiased.

Early this year, the situation with energy supplies in Eastern Europe aggravated in the wake of the Russian-Ukrainian gas conflict. In response to the newly emerged transit problems, Hungary and Croatia declared their intention to diversify gas supplies by construction of an LNG terminal in the Adriatic Sea to transport gas from North Africa. For its part, Russia wants to consolidate its positions on the East European market. Russia's oil and gas supplies to Eastern Europe account for 14% and 17% respectively, discounting its supplies to Baltic countries and former Yugoslav republics. On the whole, Russian oil and gas exports to Eastern Europe bring some 20% of the country's foreign exchange revenues.

In this respect, Vladimir Putin offered Hungary and the Czech Republic alternative energy solutions that could also work for the other countries of the region. Hungary can extend the operating Blue Stream gas pipeline to southeastern Europe, and the Czech Republic is invited to use the North European gas pipeline being stretched under the Baltic Sea directly to Germany. The two promising gas pipelines bypass the post-Soviet countries of Ukraine and Belarus apt for tapping off Russian gas.

However, Russia's oil and gas interests in Eastern Europe extend beyond stable oil and gas transportation. The country would also like to consolidate its property interests in the region, which is not a smooth process. Eastern Europe is cautious about the expansion of Russian private and state capital into its energy sector, keeping in mind its previous dependence on the U.S.S.R.

Yet, Russian energy suppliers have already made some acquisitions in Eastern Europe, and the process is likely to continue. Russia's largest oil and gas holdings - Gazprom, LUKoil and others - have repeatedly said they would like to buy assets in Eastern Europe. Gazprom has also held negotiations with heads of Hungarian ministries to discuss its participation in energy and petrochemical projects in the country. The Russian gas monopoly still wants to buy shares of the country's largest oil and gas company MOL from the Hungarian government.  Interestingly, Gazprom and LUKoil already own shares of Hungarian energy companies, primarily MOL, and still hope to buy more. However, the expansion of Russian oil and gas capital to Hungary is controlled by the country's government and the policy of national privatization institutions.

In general, buying aspirations of Russian oil and gas holdings provoke an ambiguous reaction in Eastern Europe. Slovakia, Bulgaria, Romania and former Yugoslav republics are more or less benevolent, while Poland, the Czech Republic and Hungary are more cautious. There are both political and economic reasons for that: consumer competition on the market of oil and gas assets is lower in the former group. Glories for Russian companies in Eastern Europe include LUKoil's purchase of oil refineries in Burgas, Bulgaria, and Ploeti, Romania, and quite a large network of fuel stations in the Balkans. In its turn, Gazprom joined Gaz de France and Ruhrgas in privatization of the Slovak gas pipeline company SPP. The Russian gas giant is also considering some acquisitions in Romania, Bulgaria, Serbia, Macedonia, Bosnia and Herzegovina.

At the same time, LUKoil failed to buy oil refineries in Czech Paramo and Polish Gdansk. Both LUKoil and Gazprom were not allowed to join in privatization of the Czech holdings Transgas and Unipetrol, and Gazprom had difficulty getting access to the Hungarian MOL holding. So, the starting positions of Russian oil and gas companies in their striving for ownership in Eastern Europe are not strong. Contacts between Russian companies and their East European partners bring more results in this region than those made at the state level, because the latter are often impeded by political considerations.

India’s Energy Security: Issues, Major Challenges and Policy Suggestions – V

Dr. Samir Ranjan Pradhan

Major Issues and Challenges

here are several key obstacles in realizing India's quest for stable, secure and sustainable energy supplies at relatively stable prices. While these vary in kind and in degree from one energy source to another, they are essentially two fold in nature:

·          The slow pace of sectoral reforms, internal problems of political/ bureaucratic inertia and entrenched resistance to outward looking liberalized trade and investment policies and;

·          Built-in constraints of geology and geopolitics.

The various key issues and challenges pertaining to India’s energy sector (all sub sectors) are briefly mentioned in the box given below.

Box 2:  India’s Energy sector: Major Issues and Challenges

Hydro	·          Well below Potential
	·          Long Gestation Period
	·          Implementation constraints-Rehabilitation, Environmental clearances
Coal	·          High Emissions
	·          Low Efficiency
	·          Low Calorific Value and High Ash content
	·          Concentration in Eastern and South Eastern region
Nuclear	·          Below Potential
	·          Security of Supply
	·          Implementation constraints- Uranium availability, financing, International treaties
Renewables	·          Huge Potential available
	·          Gap between technical horizon and commercial horizon
	·          Lack of investment and major players
	·          Must for rural security
	·          R & D needed
Oil & Natural Gas	·          Vulnerable to Disruptions
	·          Security of Supply-supply risk
	·          High price volatility-market risk
	·          Technical Risks
	·          Rising import bill and impact on GDP
	·          Regulatory deficits
	·          Access to Pipeline gas
	·          Leverage over LNG suppliers
	·          Huge Infrastructure Needs
	·          Distorted duty & Pricing Regime, Subsidies, inefficiency and sectoral rigidities

Source: Compiled from various Sources.

 

Though, the visible onerous challenges in the hydrocarbon sector are multifaceted, they can be broadly grouped under three heads, such as supply risk, market risk and technical risk. The various factors underlying India's quest for energy security in the past and also in the coming years can be summarized as follows:

·          Accessibility and affordability of adequate oil and gas supplies in a domestic resource deficit and globally constrained market amidst escalating oil prices.

·          Lack of Demand Management Practices (DMPs)

·          Irrational Pricing Regime and multiple distortionary duty regime

·          Slow pace of reforms and inadequate restructuring and clash of interests among decision making bodies

·          Barriers to entry for private (both domestic and foreign) players and outdated legal mandates

·          Regulatory deficits lead to sectoral malfunctioning and improper governance

·          Mal-administration of product subsidies

·          Negative environmental spill-overs due to low-gradation of products bearing huge opportunity costs

·          Inadequate domestic infrastructure and lack of investment to meet the sectoral demand

·          Technological incapability to adopt advanced sectoral practices

·          Complex geopolitical vortex to access overseas resources

Indian energy sector is overwhelmingly dominated by the central public sector organizations. Through the public sector functioning and development, lot has been achieved and simultaneously inefficiencies and distorted policy parameters have enabled structural rigidities that are plaguing the performance of the energy sector. The hydrocarbon sector is no exception, though the refining sector is scarcely presented by private players after the deregulation. The controlled pricing regimes, distortionary duty structure, over presence of political consideration in decision making have resulted in sectoral inflexibilities hindering fair competition and integrated development of the sector. In fact, the lack of synergy in reforms across all energy sub sectors has exacerbated the inflexibility in India’s energy policy space.

Moreover, lack of expertise and technical ability, financial constraints and inadequate policy decisions have compounded the problem. India's oil refining and oil recovery capabilities and overall energy technology is inadequate to meet the challenges of recent changing global energy sector. Though some public and private sector entities like ONGC Videsh Ltd. and Reliance Pvt. Ltd. have recently entered into technological alliances with foreign partners, lot is to be done to overcome these hurdles. The meager equity levels and financial strength of Indian oil and gas companies has affected the international presence. High interest rates in India relative to other countries have acted as a liability for the Indian oil and gas companies to compete for equity oil abroad. Moreover generating loans in the international market for oil and gas sector operations has not been successful due to India's lower position in world financial markets' country ranking. In addition, neither Indian banks nor the Indian government have provisions of special incentives in the form of soft loans or aids for equity oil projects.

 

Regardless of the limited efficacy of sectoral reforms, India's hopes of diversifying supply as a means of enhancing energy security have been - and will continue to be - constrained by its political geography for the foreseeable future. India's geopolitical realities in regard to oil and gas resources are in many respects, the reverse of many other Asian countries^[1]. For example, Japan has spent tens of billions of dollars over the past three decades searching for oil fields in the Middle East or pursuing oil and gas schemes with Russia in an effort to diversify supplies.

 

More recently, as we have seen, China has also purchased oil fields from Sudan to Central Asia and entertained the idea of constructing massive pipelines that have little economic rational in the hope of diversifying supplies in the name of geopolitics and energy security. India is constantly being outpaced by China in these endeavors. But for India, the opposite is true: energy projects that have a compelling economic logic are stifled by the geopolitical realities of South, central and west Asia. This can be best substantiated from the recent developments concerning to the proposed pipelines, such as Iran-Pakistan-India (IPI), Myanmar-Bangladesh-India (MBI) and Turkmenistan-Afghanistan-Pakistan-India (TAPI).

The future of Electricity Supply in Karnataka Part - V

7         Other urgent issues for the society:

ne of the main issues the society needs to concern itself with is to ensure that the electricity companies involved in generation, transmission and distribution are performing to the industry standards.  All progressive companies have a practice of benchmarking their performance at international level.  There are many forums internationally available for such purposes. Such comparisons will help in overcoming many of the inherent procedural shortcomings, and to learn and adopt the international best practices.  Most of the electricity supply companies in our country are not known to have any such bench marking process, because of which they are not only not improving their performance, but have remained a sort of liability on the society. The society should continually need to remind itself that there are many countries, which have uninterrupted electricity supply of very high quality, and the real cost of such a supply is either coming down in real terms, or at least not increasing exponentially as it is happening in India.  There is a lot we can learn from international best practices in all areas of electricity generation, transmission, distribution and utilization.  A continuous review of our practices with international industry leaders is essential to provide the better service to the society, which is the main objective of establishing the state owned electricity supply companies.  As discussed in the earlier sections, the efficient use of the existing set up and the assets themselves can go a long way in addressing many of the issues, which the different stakeholders of electricity are facing.  The following issues, amongst others, should be addressed by the society through the good offices of KERC:

7.1    Common obligations of various electricity companies:

·          Whether the planning, design, construction, specification, procurement, testing, commissioning, operation, maintenance, fault investigation, repair procedures, safety aspects, cost control; and the performance/service standards follow the industry best practices, and subjected to peer review?

·          What are the performance/service guarantees given to the stakeholders in general, and to customers in particular?

·          Is the customer satisfaction feedback obtained scientifically and regularly, and remedial actions taken earnestly?

·          How does the performance compare with the industry leaders both within the country and internationally? Without adequate benchmarking there is no way of telling whether the performances can be improved further.

·          How does it propose to accurately measure the performance indices and publish?

·          Whether quality certification like ISO certification obtained?  Few of the electricity companies in India have adopted one or more of: ISO 14001 certification for environment safeguard: OHSAS 18001 for occupational hazard; ISO 9001 for quality management system etc. These are needed to achieve not only power self sufficiency, but a quality power system; they will help to assure the stakeholders that certain systematic approaches are being adopted to maintain good quality.

·          Do they have regular interaction on all common issues with similar companies within the country and internationally?

·          What role are they playing in R&D of the respective sector?

·          How close a relationship does the company have with the public? Are the public, especially the affected sections of the society, being consulted effectively on all major projects? If so, what is the mechanism employed?

·          How is the public being kept informed of the new major projects of considerable investment and of environmental importance?

·          What are the policies adopted as far as safety (of operating personnel and public), asset management, risk management, environmental management, and the surrounding communities are concerned?

·          How do these companies compare in cost effectiveness with similar companies in India and abroad?

·          Do they have perspective plan for development over a horizon of 5 to 10 years? If so, they should be available in public domain.

·          Before they seek to increase the price of supply of electricity, do these companies have taken all possible measures to reduce the cost of such supply, and can they prove so?  In return for the increase in the supply tariff what improvements in service standards can the consumers expect?

(Views are personal)

 

India’s Energy Security: Major Challenges Part – V

 

(Brainstorming Session)

Comment: If it is because of the shortage situation then what happens is that the GDP is also lost. Part of the problem in these energy elasticity numbers is that they have to be defined with a lot of caution.  The example I give is the following: suppose I take a taxi ride from the airport to down town Mumbai. The distance is roughly the same for the taxi ride form the Kennedy Airport to Manhattan.  The amount of petrol that will be used is more or less the same. So in terms of energy used for passenger kilo-meter both are the same, value added in that ride in Mumbai would be $2 and it will be $20 in New York.  So if you look at per dollar GDP value added oil used, Americans would show that they are ten times as efficient as Indians in energy use which is not true. This is just an illusion in terms of the numbers. If you compare GDP intensity of energy across different countries there is always a problem. The same problem in a slightly different way also comes across in terms of time. Although, the weightage increases relatively we have the same problem domestically also.

Comment: You must look at sectoral elasticity - of agriculture, industry etc.  Indian GDP is now 52% services. So this probably would have to be brought out by data. 

The focus must be on why investment is not coming, either foreign investment or domestic investment?

We all know the answer. As mentioned earlier, there is no market.  Then how do we address the issue of creating an energy market in a situation where we have to prioritise between various interests. The energy crisis has to be taken as a national crisis.

Comment: It is both the centre as well as the state government’s responsibility.  How do you create some kind of awareness at the state level? Probably participation of the state level power ministers would help.

Comment: Probably, this is the first time that you have mentioned ‘life line’ energy requirement.  Otherwise it has been ignored even by the government.  To meet that life-line requirement, we need to plan and develop all sorts of energy sources. There should be coordination and development of all energy sources with equal emphasis.

There should not be greater emphasis on the product which you are importing ignoring the domestic potential of development. Of course, there are lot of vested interests which sometimes are pushing imports leading us to believe that we do not have domestic resources.  Whatever domestic resource we have must be given highest priority.  So perhaps, in the case of an integrated energy policy, we really must give first priority to domestic enhancement of all energy sources. 

Comment: What more priority can you give to the domestic energy than saying that they will get import parity pricing?

Comment: In that case it could be really a disadvantage to the consumers because import parity price today in case of gas is really not acceptable.  The example before us is the Hazira terminal - half a billion dollars have been invested and is stranded.

Comment: Pricing is an incentive. 

Comment: Can we incorporate some ideas from an international country where energy reforms have been done or energy policy has been enacted, and if so how does it differ? The US energy policy clearly says that by 2020 10 % of the energy will be made from non-conventional sources.

Comment: We have specifically stayed away from making such a statement because if we do so, then up to 10% of non-conventional energy would not qualify for getting carbon credit.

Comment: I am not saying that we should also do it.  My point is that if at some country where energy policy has been effectively implemented, we can use that to convince people that such policies have been adopted and have resulted in positive outcomes.  It is desirable to have one or two such papers.

Chair: Would you like to say something on gas infrastructure requirement, cross country pipelines or any other issue related to that and also on whether more gas can be found.

Comment: We got a comment from ONGC, which said; “how can you say that we haven’t been successful in exploration?” It is true that we didn’t find another Bombay High but it is because of our drilling that Krishna Godavari belt gas has been found.

Chair:  I have heard this before.  More than others, I have heard it from the Oil Minister in a public forum: he said that documents were stolen and that knowledge was taken.

Comment: If we are looking for import parity price which is applicable in the UK and USA, then perhaps, we need to develop infrastructure, so that gas is not left stranded. It should be easy to carry gas from one place to another as it is in the US and UK.  That type of investment will come only if there is some incentive.  Only then can we think of getting into cities.  If restrictive policies are continued then there may not be many people who will be willing to invest. There has to be some special incentive for people to invest in pipelines.  Except GAIL and one application from Reliance nobody has applied for putting up a pipeline.

Comment: If you sell at $2 per million BTU and you get a sale in Madras you can put a pipeline, if you get a sale in Bangalore you can put a pipeline.  If the price is not there, there is no sale at the end of pipeline and there is no pipeline. There is gaming going on in pricing.  If you say that power producers are going to be forced into buying gas at this high price there are people who are going to fight it – tooth and nail. Power price cannot be increased.

Chair:  Yes I agree, for Power there are alternatives. 

Comment: If power is not going to be generated through gas, then where is the demand for the gas? We are talking of demand of 400 million standard cubic meters of gas and where is that going to come from?

Comment: In most countries power is the largest marginal user of gas. Once you accept that power is the largest marginal user of gas, the large gas producer in the country will have two options. Option-I is to sell gas at the rate at which a person who is generating power would find it economical to use the gas based power rather than the coal based power or to liquefy and send it abroad.

Chair: When the oil prices were low and naptha prices were low we thought we could put up naptha based power plants.  But you could not control naptha prices. The same thing is likely to happen in case of gas-based power. One of the most well known personalities in energy and a leading economist in the world told me last year that the countries who want more gas and who can afford it are Japan and US. He said that the price is going to be in the range of $8 - $10 in the future.  When that happens, the rest of the world can forget about gas. People say that that in our country we will maintain the price at $2 but no you can’t.

Comment: No we have to be able to export it to the US at $8 and then take the rest for marginal use.

Comment: Last month, wheat price was Rs 820 a quintal. This month it is Rs 950 and nobody is saying anything. Why is that when we are talking of energy and electricity prices there is this kind of controversy.

Chair: My point is that if that is going to be the position and coal cannot reach every part of the country, what are the alternatives to meet the required amount of power in that scenario? South India doesn’t have hydro.

NEWS BRIEF

OIL & GAS

BP in JV talks with local firms

March 21, 2006. Global energy major British Petroleum is in talks with domestic oil majors to form joint ventures in exploration, production and refining. BP had held discussions with Reliance Industries (RIL), Indian Oil Corporation (IOC) and Oil and Natural Gas Corporation (ONGC) on the basis of new exploration and licensing policy (NELP) VI oil blocks bid. According to industry analysts, India urgently needs to develop its own energy resources to help sustain its rapid economic growth. It produces less than half of the oil and gas it needs. The world's largest energy companies are looking to expand their interest in India. BP is partnering with Hindustan Petroleum Corporation for the Rs 9,800 crore ($2.21 bn) Guru Gobind Singh Oil Refinery at Bathinda. British Gas is a joint venture partner in Panna, Mukta and Tapti fields with ONGC and RIL. While lubricants remains BP's main business activity in India, it is also involved with solar power, gas, power and renewables, chemicals and oil trading through various group companies in India.

Prize Petro eyes oil exploration in Iran, Oman

March 21, 2006. Prize Petroleum, a joint venture company of HPCL and financial institutions, is bidding for oil blocks in Philippines, Iran and Oman to enter the exploration and production sector in a mega-way. HPCL is likely to form joint venture with Petronas, Malaysian oil major, for the upstream initiatives in Philippines. Philippines is a proven gas-rich region. Oil exploration has not gained momentum here, thus as the initial-runner HPCL would get the benefit. The joint venture is looking to get some blocks East Asia also. Recently it has signed MoU with Chinese oil gaint Sinopec Corporation in exploration, production and refining. HPCL is evaluating the possibility of setting up a liquefied natural gas (LNG) import and regassification terminal of 5 mt in Mangalore or Mundra. Iran and Oman block acquisitions are likely for sourcing gas for these projects.

ONGC finds more gas in K-G basin

March 21, 2006. ONGC has found more gas in its deepwater block KG-DWN-98/2 in the Krishna-Godavari Basin. Gas has been found in well W-1 at the block. For the first time it has found gas accumulation below the thrust. ONGC is currently in the process of cleaning up the well. ONGC has drilled the well to a depth of over 2400 metres to find the gas. So far, ONGC has found gas in five wells at blocks A-1, D-1, E-1, U-1 and W-1 at the deepwater block in eastern offshore. After the appraisal wells are drilled, the Directorate General of Hydrocarbons certifies if the finds are commercially viable to produce. 

OVL wins Exxon's stake bid

March 20, 2006. ONGC Videsh (OVL) has clinched the Campos Basin oilfield deal and will buy a part of Exxon Mobil’s stake. The company will now partner Shell and Petrobas in its first venture in Brazil. In a quid pro quo arrangement, Petrobas and Shell are expected to tie up with ONGC for oil blocks in NELP-VI round. OVL will be signing the joint venture agreement this week. OVL’s bid price of around $400 mn (Rs 17.71 bn) for the partial stake had found favour with Exxon Mobil. OVL gets into the Brazilian oilfield by buying a part of Exxon Mobil’s stake which had put its entire 30 per cent on the block. Although OVL had bid to buy out the entire 30 per cent stake, it is likely to get only a part of it. Investment banking sources indicate that a part of Exxon Mobil’s stake is expected to be picked up by the existing partners (Shell & Petrobras) through the pre-emption route. The offshore block is located off the east coast of Brazil’s south-eastern state of Espirito Santo. Shell and Petrobras each have a 35 per cent stake in the block, while Exxon Mobil had the balance 30 per cent. Shell is the operator in the offshore block.

NTPC plans to bid for gas blocks under NELP-VI

March 17, 2006. Having bagged its first oil and gas block in Arunachal Pradesh in the fifth round of bidding under the New Exploration Licensing Policy, NTPC Ltd plans to take forward its diversification into the oil and gas exploration business with aggressive plans to bid for more acreage in domestic blocks under the recently announced sixth round of bidding under NELP-VI. The power major, which plans to pick up equity stakes in the upstream LNG chain in India and abroad to ensure the long-term availability and price competitiveness of gas or LNG for its gas-based power stations, would be bidding for gas blocks in the NELP-VI to take forward its gas exploration plans. The state-owned company, the country's largest power producer, is also working towards getting into various elements of the LNG value chain in the medium to long term. This includes possible participation in gas liquefaction and regassification terminals and LNG shipping through the joint venture route. The company is planning an initial investment of $11 mn (Rs 487 mn) for developing the NELP-V block. Its consortium partners — Canoro Resources Ltd and GeoPetrol International — would chip in with the rest of the initial investments. NTPC has a 40 per cent stake in the venture formed by the three players. The block would be developed in three phases over a seven-year period. NTPC plans to extract oil from the block to sell it in the spot markets and use the revenue stream to purchase gas for its plants.

OVL may set up JV with Petrobras

March 16, 2006. ONGC Videsh is likely to join hands with Petrobras, the Brazilian state-owned company, for exploration in Latin America. Ministerial level talks are on for a joint venture exploration and the topic will be discussed during the Indian delegation’s visit to Brazil at the end of this month. The Brazilian major has plans to join the new exploration and licensing policy (NELP) VI oil block bid. The Indian delegation is visiting London, Houston, Brisbane, Perth, Kuala Lumpur, Dubai, Calgary and Rio de Janeiro for NELP VI and coal bed methane (CBM) III bid campaign. Fifty-five blocks are on offer for bidding in the NELP VI licensing round. Among the total blocks, 24 are in deep water, 6 in shallow water and 25 are onshore. Petrobras has presence in 15 countries across three continents. It covers the entire operation chain in the oil and energy industry, ranging from oil and natural gas exploration, production and refining to gas processing, byproduct distribution, marketing and transportation through pipelines. Petrobras produces petrochemicals and generates, distributes and transmits electric energy. 

HPCL-Total talks for Vizag refinery JV off

March 21, 2006. Hindustan Petroleum Corporation Ltd's talks with French oil giant Total for equity partnership in building the 15 million metric tonnes per annum (MMTPA) export-oriented refinery-cum-petrochemical complex in Vizag have failed. HPCL will now set up the Rs 16,000 crore ($3.61 bn) project on its own. The two had been in advanced negotiations for some time. HPCL and Total were expected to own 26 per cent each in the Vizag project. The remaining 48 per cent was to be offered to public through an initial public offering (IPO). It is expected to be commissioned by the end of 2011-12. Apart from Total of France, international oil majors Saudi Aramco, Petronas and British Petroleum had also evinced interest in equity participation in the project. Equity participation in the Vizag refinery would have allowed Total an entry into petroleum retailing in India, since it would have invested more than the mandatory Rs 2,000 crore ($451 mn) which is the minimum investment required to secure licence to retail petroleum products in the country.

ONGC revises SEZ investment

March 20, 2006. The ONGC has sharply revised upwards its investment proposal for the Mangalore Special Economic Zone. It had earlier proposed to invest Rs 25,000 crore ($5.65 bn) and it is now ready to invest Rs 45,000 crore ($10.16 bn). ONGC was ready to invest in more components like expanding the refinery from 9.69 mmpta to 15 mmpta at a cost of Rs 8,000 crore ($1.81 bn), a gas track and an LNG terminal.

IOC plans 19 LPG outlets in Kerala

March 17, 2006. Indian Oil Corporation will set up 19 auto LPG stations in Kerala, making it the first state to be completely covered by a network of such stations. The state already has two such stations. IOC also plans to sell its high-performance diesel, Xtramile, at four depots of the Kerala State Road Transport Corporation and in the fishing sector. Introduction of LPG for outboard fishing boats, in association with Surya Marine, had brought down the running cost for fishermen.

BPCL, Kochi Refineries plan joint venture

March 17, 2006. The public sector companies Bharat Petroleum Corporation Ltd and Kochi Refineries Ltd have initiated efforts for setting up a joint venture company for distribution of gas in Bangalore identical to a similar venture in Kochi. The equity in the joint venture would be held by the two companies along with the Gas Authority of India Ltd. The State Government would be offered a 5 per cent equity stake in the venture and the remaining would be offered to financial institutions. The company would focus on distribution of gas in Bangalore city, both to the domestic and the industrial sector. For the Bangalore retail supply venture, the cost was estimated at slightly over Rs 600 crore ($135 mn). The gas requirement was also expected to be more than double that of Kochi. The estimated demand in Kochi is 2.4 (two point four) million standard cubic metres per day. The gas transmission to Bangalore would be through a 600-kilometre pipeline in Kochi. The pipeline project was estimated to cost at least Rs 1 crore ($0.23 mn) per kilometre.

New refinery projects to raise capacity to 210 mt

March 17, 2006. With a slew of greenfield refinery projects expected to be set up in the country, the crude oil refining capacity will surge to 210 million tonne (mt) per year by 2010. At present, the country’s refining capacity is 127.37 mt from 18 refineries. Over six greenfield refinery projects are at different stages of development, while two capacity expansion projects are under way. RIL will be a major contributor through its arm Reliance Petroleum, with a refining capacity of 60 mt in four years. Apart from RIL, Nagarjuna Oil Corporation, Essar Oil, Bharat Petroleum Corporation (BPCL), Hindustan Petroleum Corporation (HPCL) and Indian Oil Corporation (IOC) are in the fray to build-up refineries. Both IOC and RIL have started expansion in their existing refineries as well.

Iran offers IPI gas  at $6 mBtu per

March 20, 2006. At a recent tri-nation high-level meeting between Iran-Pakistan-India (IPI) on the proposed pipeline project, Iran has given the first offer price for the gas in the range of $6 per million British thermal unit (mBtu). After 18 months of negotiations, Iran has given the first price offer for gas to be delivered at the Iran-Pakistan border. The next round of secretary-level talks on gas pricing and project structure would be held in Islamabad in the last week of April. Besides the gas price, the three countries dwelt on the project structure for the proposed multi-billion dollar pipeline. The Petroleum Secretary, Mr M.S. Srinivasan, said that from the highs of $12-13 mBtu, the spot price of gas being traded globally has softened to around $7-8 mBtu. He is of the view that for the long-term contracts, gas price to stabilise at around $4.5-5 mBtu.

IOC joins hands with Russia's STG

March 17, 2006. IOC and Stroytransgaz (STG), a major Russian construction company in the oil and gas sector, signed a MoU to pursue economically attractive pipeline projects in India and abroad. The two entities earlier partnered in a consortium with Essar Construction Ltd for the successful implementation of the 133-km Baroda-Ahmedabad-Kalol gas pipeline project of Gujarat State Petronet Ltd. They have also jointly bid for the 300-km Iraq-Jordan crude oil pipeline project. IOC was expanding its existing network of nearly 10,000 km of crude oil and petroleum product pipelines across the country by implementing major projects. IOC planned to implement the Chennai-Bangalore pipeline, Panipat-Jalandhar LPG pipeline, Paradip-Ranchi-Raipur pipeline, and augment the existing Mundra-Panipat crude oil pipeline.

Govt rolls out amended oil regulator bill

March 21, 2006. Petroleum and Natural Gas Minister Murli Deora introduced the amended Petroleum and Natural Gas Regulatory Board Bill, 2006 in Lok Sabha. The bill envisages setting up a regulator for downstream petroleum and natural gas activities. The bill is aimed at regulating refining, processing, storage, transportation, distribution, marketing and sale of petroleum, petroleum products and natural gas to protect consumers' interest. Rajya Sabha had already passed the bill. The government has incorporated in the Bill, 47 of the 49 recommendations made by a parliamentary standing committee. The regulator will ensure uninterrupted and adequate supply of oil and gas in the country, besides promoting competitive markets.

New disclosure norms for oil & gas finds soon

March 20, 2006. Companies in the business of exploration and production may soon have to tread cautiously before making any announcements about new oil and gas finds by them. A consensus seems to be emerging between the Ministry of Petroleum and Natural Gas, the Directorate General of Hydrocarbons (DGH) and the Law Ministry that instead of empowering the Securities and Exchange Board of India to monitor such announcements, the norms could either be prescribed under the product-sharing contract (PSC) or a Government resolution could be issued for the purpose. The DGH has been working on the norms that would put in place a system to alert investors and stock exchanges of any premature declaration or disclosure of an oil and gas discovery made by such companies. DGH is of the view that empowering SEBI may not help as not all E&P companies are listed. Many E&P companies come with partners, which are not listed. Thus, it was felt that it should form the part of PSC signed between the Government and the company. The other option that was being considered was to come out with a Government resolution. The resolution could be similar to one that the Government came out with after dismantling of the administered price mechanism (APM), which clearly stated the procedure to be followed.

PetroMin plans ethanol-blended petrol for all states

March 20, 2006. The petroleum ministry announced plans to supply ethanol-blended petrol across India from the next sugarcane crushing season beginning October-November. This would require 0.5 million kilolitre of biofuel for five percent blending. Petrol blended with five percent ethanol, a biofuel derived from sugarcane, is already being supplied in nine states. But the programme has been running behind schedule due to the inconsistent supply of ethanol as also the price issue. Sugar industry have the capacity to produce 500 to 600 kilolitres of ethanol from private sugar mills alone. Petroleum ministry said that the main problem with the ethanol programme is that many of the state governments were not cooperating. As a result, the availability of ethanol remains an uncertain proposition. The problem lies in the fact that some of the state governments are giving first preference to the demand of the alcohol industry in the allocation of molasses.

‘Bring more oil outlets under third party norm’: Murli Deora

March 19, 2006. Oil marketing companies have been asked to bring more number of retail outlets under third party certification. This is one of the measures being suggested by Mr Murli Deora, Union Minister for Petroleum and Natural Gas, to ensure the quality of fuel supplied by these outlets and prevent adulteration of petroleum products. Public sector oil companies have been encouraging retail outlets to go in for third party inspection. Bharat Petroleum Corporation Ltd already has a large number of outlets under the third party certification. The Minister has advised them to set higher targets. Mr Deora directed oil companies to undertake surprise inspections at retail outlets and introduce GPS (global positioning system) on petrol tanks. GSP could track down tanks in transit and detect adulteration of fuel by transporters.

Link oil cess to global prices: ONGC

March 20, 2006. ONGC has requested the government to link the cess paid on indigenous crude to international prices. At present, it is a specific levy depending on the volume of crude produced. ONGC has suggested to the petroleum ministry that the oil PSUs be exempted from paying a cess if international crude oil prices fall below $34 a barrel. At present, the price is $ 65 a barrel. The company said the specific levy could continue till the prices crossed a benchmark level, which can be the present price of $65 a barrel. After that, the government could get 60 per cent of every dollar increase in prices. The company has suggested the rate of an ad-valorem levy at 20 per cent. Under the present regime, the cess worked out to be at $7 a barrel but with the cess being 20 per cent of the prices, the government would get $13 per barrel as cess. Upstream public sector companies procuring crude oil have to pay a cess on domestic production from nomination blocks under the Oil Industry (Development) Act 1974. The proceeds from the cess accrue to the Oil Industry Development Board established under the Act. The government in this year’s Budget has increased the cess to Rs 2,500  ($56.46) per million tonne from Rs 1,800 ($41) per million tonne. The move is significant as the government is yet to take a view on the Rangarajan Committee recommendations on overhaul of the duty structure and pricing in the sector. ONGC also wants proceeds from the OIDB cess to be used towards funding subsidies to the oil marketing companies.

Specific duty on petro products likely

March 20, 2006. The finance ministry is considering shifting to a regime of specific excise duties for petrol and diesel from the present system of a combination of ad valorem and specific duties. Such a shift in levy was recommended by the Rangarajan panel on pricing and taxation of petro products, as one of the ways to salvage the oil marketing companies from the current phase of “under-recoveries.” The shift would, however, come with a hike in fuel prices. The finance ministry is, however, averse to effecting a major hike in fuel subsidies, despite petroleum minister Murli Deora’s demand for the same. Fuel subsidy is budgeted at Rs 3,080 crore ($696 mn) for 2006-07. The finance ministry thinks it could partly insulate the oil marketing companies from the adverse impact of spiralling crude oil prices, through specific excise duties on petrol and diesel. One reason for the ministry’s inclination to endorse the Rangarajan panel’s proposal for specific excise duties was it was reconciled to shrinking excise revenues anyway. Petroleum sector accounts for over 40 per cent of the government’s budgeted excise revenue of Rs 1.1 trillion in 2005-06.

POWER

Power from Dadri project by ’09

March 21, 2006. The 5,600 MW Dadri power generation project will begin by 2009. It is expected to reduce power shortage in Uttar Pradesh substantially, while also benefiting the neighbouring states of Delhi, Haryana, Punjab, and Rajasthan. The company will be spending Rs 20 crore ($4.51 mn) on environmental conservation work on the project site. Reliance Energy Generation Ltd (REGL) said, as soon as the work is completed in the Dhirubhai Ambani Energy City at Dadri near Ghaziabad by 2009, the state shall begin getting electricity. The project had already received mandatory clearances from the Central and UP government authorities, including the civil aviation department and the ministry of environment. The continuous availability of gas being the prerequisite for the operation of this power project, discussions for supply of gas by sourcing it from RIL’s Krishna–Godavari gas field were in advanced stages and a leading bank of the country had even completed its appraisal of the project for debt financing. 

Tata Power plans 2 coastal plants in Maharashtra

March 20, 2006. Tata Power Company, which was in the process of finalising a 1,000 MW coastal power plant in Maharashtra, may now put up two 1,000 MW plants if conditions prove favourable. The company had been looking at a coastal plant near Mumbai, at a location called Vile, but had to revisit its plans again to so as to be able to create a captive jetty for fuel that could also be located close to the plant. The company is also in process of setting a 250-MW coal-based unit (number 8) at the company's Trombay thermal station. This plant, which will involve a total investment of Rs 860 crore ($194 mn), will be completed within 28 months. The unit will use imported coal with a low sulphur and ash content. The 1000-MW coastal plant should be completed by 2010. There are two super-critical units to the power plant, the setting up of which will differ from each other by seven to eight months.

RPG to invest in thermal project

March 17, 2006. The Rs 9,000 cr ($2.03 bn) RPG Group is keen on investing in a mega thermal power project with a minimum capacity of 4,000 MW. The group is working overtime to prepare bid papers for the Sasan project in Madhya Pradesh, for which the Union Ministry of Power has floated global tender inviting bids from private investors within March 31, 2006. In fact, the Ministry has plans to offer five mega power projects to private enterprises, each with a capacity of 4,000 MW. All these projects are to be completed by 2011. The estimated cost of a mega project would be about Rs 15,000 crore ($3.39 bn), and the group was confident that it would be able to arrange necessary funds for the project.

9 power plants lined up for coastal areas

March 17, 2006. The government plans to set up nine coal-based coastal power plants with a capacity to generate 10,900 MW of electricity. Discussions have been initiated with states like Maharashtra and Gujarat for this purpose. The move comes in the wake of the government planning to import nearly 20 mt of coal next fiscal due to the current domestic coal shortage. The government wants to go in for coastal power projects as that will not only save on transportation costs but also require minimal infrastructure arrangements in terms of additional wagons. Among the proposed five ultra mega-power projects, three are planned in the coastal areas. These include Adani in Gujarat, Karwar and Mangalore in Karnataka. The plants will possess dual coal use capability and be able to run on domestic or imported coal depending on availability. 

Essar to genrate power from refinery residue

March 15, 2006. Essar Power Ltd will bring online a plant using refinery residue for electricity this year and plans to build gas and coal-fired plants to avoid high oil prices and capitalise on surging demand. The unlisted firm will complete a $100 mn (Rs 4.41 bn), 100 MW power unit using waste oil from Essar's Jamnagar refinery in western India by June, to add to an existing 800 MW of gas and 100 MW of coal generation. The use of refinery residue, which resembles bitumen, for power was cheaper than costly fuel oil but was unlikely to become a trend for Asian power companies, as many refiners would turn it into petroleum coke or mix it with diesel to make fuel oil. It has a good calorific value and is a little cheaper than fuel oil. There is also no transportation required -- the residue is so thick it can't be transported. Essar Oil Ltd is boosting its oil production with a new 210,000 barrel-per-day (bpd) refinery in western India, on track for operation by this December, while Essar Power expects to build a 1,000 MW coal plant in central India and a 1,500 MW gas plant in Hazira, western India.

Jindal India, MP ink power deal

March 15, 2006. Jindal India Thermal Power Ltd, promoted by the BC Jindal group, and the Madhya Pradesh Trade and Facilitation Corporation Ltd (TRIFAC), a state government undertaking, signed a MoU under which the former will set up a 1,000 MW thermal project in stages in the Sidhi district. It will be a greenfield coal-based pithead plant. The first stage of the power plant is expected to be of a 250 MW capacity while the second and third will be of 250 MW and 500 MW, respectively. The first phase of the project is likely to be completed by 2009.  The project may be completed with an investment of Rs 4500 crore ($1.02 bn) approximately. The coal for the project is to be supplied by Singlrauli coalfields, while water supply will be ensured from Rihand reservoir. 

Shriya to set up 200 MW plant in UP

March 15, 2006. Shriya International Oil and Energy Ltd is setting up a 200 MW gas-based thermal power plant (combined cycle plant) at Rae Bareilly in Uttar Pradesh at a cost of around Rs 950 crore ($215 mn). The company has entered into fuel supply agreement with GAIL India for 47,597 million British thermal units (mmbtu) per day. Existing Hazira-Bijapur-Jagdishpur (HBJ) may be considered for gas transmission to the plant. The project will be part funded by equity of Rs 330 crore ($74.8 mn).

The rest will be debt and internal accruals. The company is negotiating a power purchase agreement with the PowerGrid Corporation. It hopes to enter the power distribution sector as well. The company is in talks with the Power Finance Corporation and the International Finance Corporation for loans. It is expecting the gas supply to start by mid-2008 and the plant to start around the same time. At an efficiency of 53 per cent, the generation cost per unit will work out to be Rs 1.93. Shriya International Oil and Energy Ltd had earlier helped set up power plants in Ukraine. The deals in oil, gas, and conventional and non-conventional energy. 

PowerGrid, REL get bids for Parbati transmission

March 21, 2006. The state-run Power Grid Corporation and Reliance Energy Ltd (REL) have received bids for laying 800 cr ($180 mn) transmission line for the 800 MW Parbati hydel project that would pump electricity for northern states. The companies are in the midst of evaluation of these bids that were opened recently. PowerGrid would hold 26 per cent stakes, while the majority stakes of 74 per cent are to be held by REL. PowerGrid, however, would retain chairmanship of the proposed JV. The project would be developed on a build-own-operate-transfer basis for 25 years, as the Parbati hydro station is expected to get operational in 2008.

Captive power plants to chip in 90 MW for Pune

March 21, 2006. A Confederation of Indian Industry (CII) proposal to augment Pune's power supply has been approved by the Maharashtra Electricity Regulatory Commission (MERC). The proposal envisages captive generation of power during peak hours by 30 CII member companies and use the power for their plants, thereby making available about 90 MW power for supply to the city.  The path-breaking proposal would mitigate load shedding in the city by running at least 30 captive power plants. MERC also approved the rates at which Maharashtra State Distribution Company Limited (MSEDCL) will reimburse the cost of power generated by the member companies. The power generated from these captive units will be routed for consumption by the public. MERC will adopt the principles of normative pricing, in relation to the fuel used and the heat rate, to determine the cost at which the captive generators would be generating the electricity. The price of fuel will be benchmarked to publicly available data on fuel prices from sources such as India Oil Corp, Hindustan Petroleum, Bharat Petroleum and Reliance Energy among others. Further, with Maharashtra government's sales tax waiver on liquid fuels used for captive power generation, the additional cost to be recovered from consumers will reduce by around 25 per cent as compared to cost estimated in CII proposal. 

Tata Power moots 7-20 pc tariff hike

March 20, 2006. Tata Power Company (TPC), in its tariff revision and annual revenue requirement (ARR) proposal submitted to Maharashtra Electricity Regulatory Commission (Merc) has proposed an average hike of 7 per cent to 20 per cent charged to Brihan Mumbai Electric Supply and Transport (BEST) and Reliance Energy ltd (REL) and also to its own consumers. On the other hand, REL, which supplies power to over 2 million consumers, has not proposed any change in tariff for meeting its ARR for 2006-07. However, REL has appealed to Merc for introduction of uniform retail tariff based on consumer mix of all utilities in Mumbai. It wants Merc to impose a cross-subsidy surcharge on all TPC consumers to protect it from loss of cross-subsidy and in view of high component of subsidy. The proposed hike for BEST and REL and TPC’s own consumers have been mainly due to increase in fuel prices and also on account of fuel adjustment cost (FAC).

Govt to allow FDI to fuel nuke charge

March 21, 2006. India has set out to make its first moves to attract larger investments in the nuclear power sector by working on a Cabinet proposal to allow foreign and private investments in the sector. The government will be introducing a bill in Parliament to amend the existing Atomic Energy Act to allow private investments as soon as the US Congress clears the Indo-US agreement. Initial indications are that the government is likely to allow FDI up to 49 per cent in the nuclear power sector. There would be no problems in inviting foreign technology and finance to expand the reach of the civil nuclear programme in the country once the separation of the plants goes through. The officials said that the present bar on FDI for atomic energy establishments was based on strategic considerations. But that argument would not be relevant for civilian nuclear power units, which would be treated on par with other sectors. The new amendment will enable production and supply of nuclear power by companies in the private sector through an amendment of Section 3(a) of the act. Amendments to the atomic energy act will also be introduced to ensure that the nuclear operator — private or public sector — will store and reprocess the spent fuel for recycling in power reactor in accordance with the stipulation in force. In case, the fuel is imported from abroad, the spent fuel will need to be sent back to the country of origin. However, the government plans to consider option of owning the spent fuel if the exporting country does not take back the spent fuel. This will be possible through the introduction of a new section, 15 A, in the proposed revised act. Leading power companies like Reliance Energy, Tata Power and NTPC are among the first few companies which have already drawn up plans to put in investments in the nuclear power sector once it is opened up.

Govt looks to captive power units to make up the shortfall

March 21, 2006.  The government is planning to tap captive producers of power across the country in a desperate move to meet the increasing gap between demand and supply. The ministry of power is writing to all state governments to establish the captive power capacity as well as surplus available in the segment, after which the state electricity commissions will determine a commercial rate for the surplus power from the captive plants. In peak summer, there is 8 per cent gap between availability and requirement, at peak hours it goes as high as 12.5 per cent, with the western region leading the way with a 20.5 per cent peaking shortage. The government is working on a plan to tap surplus power generated by captive power plants. At present captive power plants account for nearly 40,000 MW of capacity, and it is expected that 4,000-5,000 MW could be tapped by the grid. The government is targeting to add about 1,000 MW of capacity from captive power plants to the electricity grid in the next five-six years as part of efforts to mitigate power shortages in the country. During 10th plan, about 3,000 MW of surplus captive capacity would be added to the grid. In the subsequent five years, the power ministry expect that 11,000-12,000 MW of captive power could be added. In a bid to work out a national plan to tap surplus power from captive plants, the ministry of power and Central Electricity Authority in association with Power Finance Corporation organised a workshop to dialogue with captive power producers. The ministry and regulatory commissions have been working to facilitate expansion of captive capacity and connectivity of their surplus power to the grid. The government has also relaxed the criteria for terming a power plant as captive.

Committee formed to curb illegal coal mining

March 21, 2006. The government has decided to constitute a high-level committee, which would prepare a blueprint to check illegal coal mining menace. The committee, to be chaired by minister of state for coal Dasari Narayana Rao, will submit its report within a month from its constitution. The committee would identify areas most susceptible to illegal mining — both in the leasehold area of coal companies and outside the leasehold areas – and suggest measures to bring this activity to an end. Around 15 to 20 mt of coal are illegally mined annually by the coal mafia that has a strong hold in the coal bearing regions, especially in Jharkhand and West Bengal. The committee will also look into socio-economic dimensions, a prime reason for the activity of coal mafia. As coal mining in the country is largely restricted to government companies, the committee is likely to specify the role and responsibility of the public sector undertakings and make them more accountable. A joint task force comprising representatives of the Centre, the state governments and coal companies may also be recommended to prevent illegal mining. Besides, the committee will also address the issue pertaining to implementation of specific technological innovations to effectively seal the abandoned mines. This is essential as abandoned mines are prime areas for illegal mining where both environmental and safety concerns are sidestepped.

Centre to reform APDRP

March 20, 2006. The Centre, in a serious bid to give a further push to promote states to encourage reduction in aggregate transmission and commercial (AT&C) losses, proposes to restructure the ongoing accelerate power development and reform programme (APDRP). The 36 per cent of AT&C losses and losses of Rs 24,000 crore ($5.42 bn) incurred by state electricity boards (SEBs) are the matter of serious concern. The present rate of reduction in AT&C losses by a paltry 1.5 per cent is quite low, as it will take at least 15 to 20 years to reduce it to a level of 10 to 15 per cent. The Centre is of the view that it should not take more than four years for SEBs to achieve the level of 10 to 15 per cent. Currently, the centre gives grant to states to reduce AT&C losses by strengthening the transmission and distribution systems under the APDRP.

India to keep Russia within energy matrix

March 17, 2006. Prime Minister Manmohan Singh said that Russia will not remain outside the matrix of India’s energy needs, and underlined opportunities for Russia to expand partnership in civilian nuclear cooperation. Mr Singh also thanked Russia for agreeing to supply 60 tonnes of urgently needed uranium for the Tarapur atomic power plant while hinting at the possibility of involving Moscow in the Iran-India gas pipeline project.

Hydro-electricity generation projects in hill states face problems

March 17, 2006. As the installed power capacity in India crosses the 1,00,000 megawatt mark and the government aims for complete rural electrification, the need for generating renewable energy to augment energy generated by conventional means has become more important than ever before. However, owing to lack of infrastructure and legislative backing, production of power by small hydel plants is not viable, says a report. The report says that a lot of hydro power potential exists in the Himalayan hill states of India. Such projects would also help generate employment in these states, promote tourism, bring about self-reliance and peace to the villagers residing in the poor villages at the borders. These would also help control environmental degradation to a great extent. However, most of the hydel power plants in the Himalayas were small, widely dispersed, located in remote villages, involve higher cost of generation and higher capital cost and lack infrastructure, says the report. These villages do not have other industries, and consequently, with the lack of transmission lines, have no demand for the power generated by the hydel plants. Consequently, the state electricity boards (SEBs) in these regions, who are the only buyers as per present policy, are unwilling to buy power at incentive prices that assure viability. The report points out that small renewable power projects are forced to sell their product directly to monopoly buyers, in this case, SEBs, which do not give them a good deal as they cannot solve the problem of power shortage during peak hours. The report suggests an aggregating or trading agency which would provide the economic link between the two. Most renewable energy projects located in remote villages do not have wheeling or transmission infrastructure, according to the report. Small hydel projects do not have the financial capability to provide for this infrastructure as cost of generation is already high for them. Finally, the report says that finalising the national renewable energy policy draft is urgently required for promoting the development of these projects and sustaining them. 

Electrification frameworks may go

March 17, 2006. The ministry of power is working on a new electrification policy under which nearly 75 per cent of the country is likely to be freed from regulatory frameworks. Under the new policy which aims to speed up the rural electrification drive, any unit that has set up a generator and transmission networks in a declared rural area, can sell power at a market determined price. Also, for the first time, the ministry would be allowing a price discovery mechanism to operate in the power sector. So far, all the power generated in the country is sold at prices pre-determined by the Central and state electricity regulatory commissions. Under the new policy, which is expected to be finalised in near future, states have to declare designated rural areas where these privately managed or franchisee projects will be allowed to come up. These projects can be anything from micro-hydel to bio-mass, wind energy or diesel-based projects. For example, if there are 20 small generators in an area and each one generates 100 kW, under the new policy, they can come together to put up a 2 MW generation unit and sell power to consumers who want to buy it at a price determined by the market. They can set up generation units and their own transmission networks for distribution. These franchisees will be entirely free from the regulatory framework in terms of both setting up the power plants, as well as for transmitting and selling power. So, if a company is setting up a factory in a designated rural area, it can generate power for its own use, as well as sell the same to other users nearby. 

Regulators seek review of installed capacity

March 17, 2006. A group appointed by the Forum of Regulators has suggested that state electricity regulatory commissions figure out the total installed captive capacity in their states. They should also identify the availability of firm and in-firm captive generation separately. The panel’s observation assumes significance on the backdrop of the fact that over 6,500 MW of surplus power lying idle at captive power plants can be connected to grid. The group has observed that the Central and state grids are now strong enough to absorb the effects of disturbances and thus there was little justification for the levy of parallel operation charges or grid support charges. According to the group, SERCs should ensure that the parallel operational charges and grid support charges be as low as possible.

Import target heat on power firms

March 15, 2006. Power utilities may be penalised for importing less than the targeted amount of coal. One of the options being explored is to reduce the subsequent year's domestic allotment of coal by an amount equivalent to the shortfall. The move was aimed at following a carrot and stick approach by incentivising imports but also discouraging companies that do not import and miss their generation capacity targets. Under the current practice, the power ministry sets targets for power utilities with regard to the quantum of imports through the year. The move is meant to encourage import of cost effective coal. The proposal was mooted by the power ministry in response to a suggestion of the Energy Coordination Committee to levy a 3-5 per cent cess on domestic coal to encourage import of coal. The proceeds from the cess would then be used for improving infrastructure for the energy sector. However, the Committee of Secretaries on Power found that the power utilities were willing to import coal even without imposition of a cess and had already placed orders for the same. The ministry of power will closely co-ordinate with the shipping and railways ministry to ensure that there was no infrastructure constraint for importing 20 mt of coal in the next fiscal. The shipping ministry said while 13 mt of imported coal could be handled by the major ports, the minor ports under state governments would handle the balance.

Govt plans `Atomic Parks'

March 14, 2006. In the wake of the recent US-India civilian nuclear deal, the Centre is thinking of setting up `Atomic Parks' to augment nuclear power generation capacity at a fast pace. The proposal is aimed at setting up a large number of nuclear power units at each site to achieve the twin prong strategy of enhancing the potential for new capacity addition and also streamlining the process of possible International Atomic Energy Agency inspections of the civilian nuclear sites in the future, as envisaged under the nuclear deal. The Prime Minister's Office has initiated groundwork on the proposal and utilities such as the Nuclear Power Corporation of India Ltd (NPCIL) have been sounded out on the plans to have such designated sites for harnessing nuclear generation in the country. India currently has 22 nuclear stations in various locations across the country, of which 14 have been designated for civilian use under the Indo-US nuclear deal. With the possible entry of new players into nuclear power generation, including private sector companies, the `Atomic Parks' concept is expected to gain currency. According to NPCIL estimates, the country could add between 20,000 and 40,000 MW of nuclear power generation capacity over the next 10 years or so if several more players, including private sector companies, enter the sector.

OIL & GAS

Chevron gives up Nigerian oil exploration block

March 20, 2006. U.S. oil major Chevron and its partners in Nigerian deep-water oil exploration block 250 have agreed to relinquish the acreage after failing to find commercial quantities of oil. Oil Prospecting Lease (OPL) 250 was hotly contested in a Nigerian exploration licensing round in 2000 as it was thought to be one of the more promising blocks on offer. Chevron and Royal Dutch Shell battled hard for control of the block before agreeing to be partners in the venture. The firms' withdrawal from the block is a blow for Nigeria, which hopes to boost its 2.4 million barrels per day crude oil output thanks to deep-water production. Companies are also looking to offshore blocks as safer to operate than the onshore or shallow water oilfields in the volatile Niger Delta. A quarter of Nigerian oil production is currently shut down because of a series of militant attacks on oil sector infrastructure in the Niger Delta. Chevron, along with its partners in OPL 250, have decided to relinquish their holdings in the block. The unanimous decision follows the evaluation and interpretation of exploration data collected from the field, including results from drilled exploratory wells. The award of block 250 to Chevron as operator, in Dec. 2000, caused controversy at the time because Shell had bid $200 million for the block, compared with Chevron's $60 million.

NIOC invests $35bn in South Pars Gas Field

March 20, 2006. Approximate capital investment by the National Iranian Oil Company (NIOC) in developing South Pars gas field amounts to about 35 billion dollars. The field can produce 28 billion cu. ft. gas per day. Investment in producing gas from phases 1-10 as well as phases 12, 15, 16, 17, and 18 of the field aims at daily production of 17 billion cu. ft. gas and the rest of phase whose contract has not been finalized yet are to produce 100 billion cu. ft. gas per day.

The current level of cooperation between the two countries is not satisfactory and expressed hope that the two countries would soon reach a common platform for joint production from South Pars gas field. Based on current plans, Iran will be producing as much gas as Qatar by 2012. Iran’s production had caught up with that of Qatar by 2005, but Qatar is increasing its output through implementing new projects and Iran will again catch up with its neighbor in terms of gas production from South Pars gas field by 2012.

OPEC cuts 2006 World Oil Demand growth

March 17, 2006.  Citing lower consumption in the U.S. and Asia, the Organization of Petroleum Exporting Countries trimmed its forecast for global oil demand growth in 2006 by 110,000 barrels a day. Global oil demand growth for the present year has been revised down to account for a persistent year-on-year contraction in U.S. demand during January and February as well as a more pessimistic view of growth in non-OECD Asia. OPEC set 2006 oil demand growth at 1.46 million b/d and demand for the year at 84.5 million b/d. This brings OPEC's estimate in line with recent downward revisions at other forecasting agencies the International Energy Agency and the Energy Information Administration. OPEC also revised down demand for its crude in the second quarter of this year by 200,000 b/d to 27.4 million b/d.

The group produced 29.7 million b/d in February, with Iraqi output recovering to 1.8 million b/d, as weather conditions in the Persian Gulf improved, allowing more loadings. Non-OPEC oil supply growth was revised down slightly to average 1.4 million b/d this year. The impact of historical revisions, recent performance, unplanned shutdowns as well as minor adjustments to the outlook for Mexico, Norway, Australia, Brazil, Egypt, Sudan have resulted in some revisions on a quarterly basis and a downward adjustment of 70,000 b/d to the full-year growth forecast. Refinery capacity is expected to increase by 850,000 b/d in 2006, about half the expected incremental demand for the year, with most of the increase coming from Asia. Such a shortfall would only tighten capacity for complex refineries, boosting margins and returning products to the driver seat of the oil market.

Total gets exploration block off Cameroon

March 16, 2006. Cameroon has awarded the Bomana exploration block in the offshore Rio Del Rey basin to Total SA, which will be operator with a 100 per cent interest. The 140-sq-km block is near other Cameroon blocks Total operates, producing about 60,000 b/d of oil. Total operates the Rio Del Rey permit, in which Pecten Cameroon Co. and state-owned Ste. Nationale des Hydrocarbures also hold interests. And it was awarded the Dissoni exploration block in April 2005.

PetroVietnam makes discoveries in Algeria & Malaysia

March 16, 2006. PetroVietnam Investment & Development Company (PIDC), a wholly owned subsidiary of PetroVietnam, announces its success in two exploration projects in Algeria and Malaysia. In Algeria, as the operator of the Exploration, Appraisal and Production project for Blocks 433a & 416b in the Sahara Desert, PIDC has executed the project since mid 2003 with 40 per cent of participating interest. The other partners in the contract are PTTEP Algeria and the national oil company of Algeria (Sonatrach) with the participating interests of 35 per cent and 25 per cent respectively. During the drilling program in 2005, the appraisal well (BRS-6bis) was drilled to a total depth of 3930 meters and completed as an oil production well. The Ordovician Hamra sandstone reservoir was confirmed and tested at a flowing rate of 5,120 BOPD and 4.8 MMSCFPD at the choke size of 40/64. It is expected the first oil production by the year 2009.

In Malaysia, under the Tripatite Cooperation among three national oil companies of Vietnam, Malaysia and Indonesia, PIDC has been jointly operating the exploration project for Block SK305, offshore Sarawak, Malaysia, with its participating interest of 30 per cent. The first commitment well (Dana-1X) was spudded in October 2005 and the final test was made with the main flow rate of 3,300 BOPD and 1.55 MMSCFPD at the choke size of 40/64. Currently, the parties are evaluating the potential of the block and designing the succeeding exploration and appraisal program.

Egypt calls bids for 20 exploration blocks

March 13, 2006. Egypt has invited bids for a total of 20 exploration blocks, which will be awarded in separate bidding rounds. The Egyptian Natural Gas Holding Company (EGAS) has invited bids for 12 exploration blocks four offshore in the East Mediterranean, another four offshore in West Mediterranean, one offshore in the Mediterranean, and three onshore in the Nile Delta and two in Sinai, covering a total area of 60,913 sq. km. The bids, opened on February 15, will close on July 16, 2006. EGAS anticipates substantial discoveries of natural gas in the region.

For its part, the Ganoub El-Wadi Holding Petroleum Company has invited bids for eight blocks, four offshore in the Red Sea and the Gulf of Suez, and four onshore in the Western Desert and the Eastern Desert. The eight blocks cover a total area of 157,588 sq. km. The bids, opened on March 1, will close on July 16.

Egyptian gas reserves are estimated at 67 trillion cubic feet, but with recent discoveries it is believed that the actual reserves may be well about 200 trillion cubic feet. The situation concerning oil is the reverse, as Egyptian crude oil production has been continually declining, falling to 578,945 barrels a day in 2005, compared with 594,657 in 2004.

China in $3bn refinery venture in Angola

March 21, 2006. Angola had partnered with China to move ahead with construction of a $3 billion oil refinery in the port of Lobito. State oil firm Sonangol said in December that construction could start this year and that it was upbeat about finding investors for the project. China is keen on oil from West Africa to fuel its rapid economic expansion. Traders reported that the total flow of West African crude set to go to Asia in March matched the all-time high, buoyed by Chinese buying.

Angola is sub-Saharan Africa's second largest crude producer after Nigeria. It churns out around 1.3 million barrels of oil per day and this is expected to rise to 2 million barrels per day as a number of new developments come onstream. Angola had said it would like to see the refinery's capacity reach about 200,000 barrels per day. The new refinery will permit Angola to reduce imports and start to export value-added petroleum goods. The Ministry of Petroleum estimates that 80 per cent of Lobito's production will be for export, principally serving regional countries.

India bonds for cheap fuel

March 20, 2006. Indian Oil Corp and its state-run rivals will receive government bonds by the end of this month as compensation for selling fuels below world prices. The first tranche of 57.5 billion rupees (HK$10.03 billion) was given to refiners on March 7 and the second equal installment will be issued before the month ends. Indian refiners' profits are eroded by a state-imposed cap on fuel prices aimed at shielding consumers from a 40 per cent surge in crude oil costs last year. Refiners were allowed to raise gasoline and diesel prices by 15 percent last year. In the first tranche, IOC got 34.5 billion rupees of the securities, while Bharat Petroleum Corp got 11.01 billion rupees and Hindustan Petroleum Corp got 12 billion.

Seven petrochemical plants soon in Iran

March 19, 2006. Seven new petrochemical plants will come on stream in the next year. Along with the crude oil sales, other oil products including petrochemicals as well as the natural gas are also exported while 100 years after the oil discovery in Iran the country was still a mere crude exporter.

Saudi on $10 bn petrochemical project

March 19, 2006. Saudi Arabia started work on a $10 billion refinery and petrochemical complex, at least 25 per cent of which it plans to float.  Petrorabigh, a joint venture with Japan's Sumitomo Chemical Co.is due to start production in the second half of 2008. It will produce 18.4 million tonnes of oil products, 1.3 million tonnes of ethylene and 900,000 tonnes of propylene a year. Sumitomo and Saudi state-owned Aramco agreed in May to develop the petrochemical complex through a 50-50 joint venture that would upgrade a refinery at Rabigh on the Red Sea. Under the pact, Aramco's first foray into the petrochemical business, the oil giant will supply the project with 400,000 barrels per day of crude oil, 95 million cubic feet a day of ethane and about 15,000 bpd of butane. Riyadh has said it plans to invest $50 billion to boost crude production capacity to 12.5 million bpd by the end of the decade from 11 million bpd now to meet future global demand. The plan calls for capacity to hit 15 million bpd in later years.

Gulf OPEC investments in Asian refineries

March 16, 2006. Middle East OPEC members have invested heavily in Asian refineries over the past decade and stepped up their efforts in the past year, securing them a ready market for future crude oil exports. Iran, OPEC's second-largest producer, has lagged other countries such as Saudi Arabia, Kuwait and the United Arab Emirates in the drive, but agreed last year to build a refinery in fellow OPEC member Indonesia.

In Japan, Saudi Arabia's state oil firm Saudi Aramco bought a 10 percent stake in Showa Shell, Japan's sixth-largest refiner with capacity of 530,000 barrels per day (bpd), from Royal Dutch Shell in 2004. It raised that to 15 percent last year. Saudi Arabia doubled sales to Showa Shell to 300,000 bpd after the deal.

In China, Saudi Aramco is partnering with Exxon Mobil Corp. and Sinopec Corp. in a $3.5 billion expansion project that will triple the capacity of a plant in Fujian to 230,000 bpd.  It is in talks to take a 20-40 percent stake in Sinopec's new 200,000-bpd refinery in Qingdao, which is under construction and due to start up in 2007 or 2008. Kuwait Petroleum Corp. agreed last year to build a $5 billion, 300,000-to-350,000-bpd refinery with PetroChina in southern Guangdong province and has said it was seeking a second such project.

In India, The National Iranian Oil Company (NIOC) has a 15.6 percent stake in Chennai Petroleum Corp. Ltd., a 210,000-bpd refining subsidiary of state-run Indian Oil Corp. (IOC) that was formed as a joint venture between Iran, India and Amoco in the 1960s.

In South Korea, Saudi Aramco owns a 35 percent-stake in S-Oil, South Korea's third-largest refiner, which is seeking permission to build a 440,000-bpd refinery, taking its total capacity to more than 1 million bpd. Abu Dhabi investment fund IPIC last month raised its stake in Hyundai Oilbank, South Korea's fourth-biggest refiner with a 390,000-bpd capacity, to 70 percent from 50 percent.

In Taiwan, Abu Dhabi's IPIC has been seeking for months to buy an up to 25 percent stake in Taiwan's government-owned Chinese Petroleum Corp (CPC), with a refining capacity of 770,000 bpd. A MoU on the purchase expired last November and Taiwan has not offered CPC for sale.

In Philippines, Saudi Aramco has a 40 percent stake in refiner Petron, which is upgrading its thermal cracking unit to maximise gasoline output as part of a $300 million investment project. The refinery has a capacity of 180,000 bpd.  Aramco is also planning a feasibility study for a new oil refinery on the southern island of Mindanao.

In Indonesia, Iran signed an MoU last year to build a 300,000-bpd, $2.5 billion refinery in Indonesia, whose limited refining capacity forces it to import fuels. There has been little progress on the project since.  

China may seek agreement from Russia on oil pipeline

March 21, 2006. China may seek agreements for Russia to increase shipments of oil and gas to the world’s most-populous nation when Russian President visits Beijing. China wants an $11.5 billion oil pipeline from eastern Siberia to the Pacific coast port of Nakhoda to include a spur going into China, the world’s second-biggest oil consumer. Russia is scheduled to start building the pipeline this year.  China is seeking to secure long-term supplies for the world’s fastest-growing major economy. Russia may be willing to offer China some of what China wants in order to win Chinese military equipment orders and investment in Russian technology companies as part of an effort to diversify the nation’s economy away from natural resources. China and Russia will sign three energy-related agreements in Beijing.

Gazprom eyes move into Belgian market

March 20, 2006. Energy giant Gazprom has spoken to the Belgian government about moving into the country's gas market as it opens up to competition. Gazprom was attracted by the country's gas transport links through Belgium's Zeebrugge port, which would allow it to export to other countries. Eight or nine European energy firms have expressed interest in the Belgian gas and electricity markets. Belgium has to open its energy markets by July 2007 and is likely to face EU criticism in the coming months for not doing enough to meet that deadline because the country's energy sector is still controlled by a few major players. The Suez-Gaz de France tie-up would create a major new European player in energy, water and waste services with a market capitalization of $86 billion. The deal is likely to face tough scrutiny from EU antitrust regulators.

Greece, Russia to speed up pipeline project

March 17, 2006. Greece and Russia plan to accelerate work on a major energy project that will allow the latter to export oil to Europe in circumvention of the world's busiest shipping lanes. The Russian, Bulgarian and Greek governments signed a memorandum on the construction of a pipeline stretching for 280 kilometers (175 miles) from the Bulgarian port of Burgas on the Black Sea to Greece's Alexandroupolis on the Aegean in April 2005. The project, which is expected to cost at least $800 million, will allow Russia to export oil through the Black Sea bypassing the busy Bosporus Strait in Turkey. Initial throughput capacity will be 35 metric million tons (255 million bbl) metric tons of oil before rising to 50 million tons (370 million bbl).

MMS signs 10-year gas transportation deal

March 15, 2006. The US Minerals Management Service has signed a 10-year agreement to transport more than 50 MMcfd of royalty in-kind natural gas through the 1,323-mile Rockies Express Pipeline under construction from Wyoming and Colorado to the US East. The agreement needs Federal Energy Regulatory Commission approval. The pipeline commitment will enable the service to expand its royalty-in-kind program in Wyoming and give it flexibility to move gas to areas of greatest demand.

Petro-Canada, Gazprom plan $1.5 bn LNG plant

March 14, 2006. Petro-Canada and partner OAO Gazprom are planning a liquefied natural-gas plant near St. Petersburg, Russia, worth up to $1.5 billion that would supply gas to Petro-Canada and other customers by 2010. The two companies will go ahead with engineering studies for the proposed Baltic gas liquefaction project to provide cost, size and timing for the plant. The preliminary work is expected to be completed by year-end. Most of the gas produced by the proposed plant would be shipped to the planned Gros Cacouna re-gasification plant in Canada owned by Petro-Canada and TransCanada Corp. There are dozens of new liquefied natural-gas import terminals planned for the U.S. and Canada as demand for the fuel rises while North American supplies are dwindling. However few of those facilities have locked up the offshore gas needed for their projects.

Norway will keep a grip on oil money: PM

March 21, 2006. Norway’s centre-left government will stick to rules limiting spending of the nation’s oil wealth but will not be mechanical in applying the curb. Under guidelines set by parliament, the government can spend up to 4 per cent yearly of a 1.4 trillion crowns ($214.4 billion) oil fund — which is invested in foreign stocks and bonds to pay future pensions — to plug gaps in the budget. The oil fund has ballooned since it was set up in 1996. Norway is the world’s number three oil exporter behind Saudi Arabia and Russia and pumps almost three million barrels of oil a day.

Deal for ME first energy exchange

March 21, 2006. Gulf Energy, signed MoU with the Qatar Financial Centre Authority (QFCA) and the Qatar Financial Centre Regulatory Authority (QFCRA), paving the way to establish the Middle East’s first dedicated energy trading platform – the International Mercantile Exchange (IMEX). The IMEX would offer a next generation of mercantile exchange for the institutions in the Middle East by giving a new dimension to the existing expertise in hedge help to facilitate the LNG and crude businesses.  Gulf Energy is a global consortium of energy experts that works to generate high value-adding business ideas and see them implemented to the benefit of energy stakeholders worldwide. With Qatar being on track to be the leading exporter of LNG by 2010 and an important exporter of oil, the introduction of IMEX fits well in the country’s dedication to the energy sector and world-class finance.

Big oil firms struggle to find new reserves

March 18, 2006. Big U.S. oil firms more than matched the oil and gas they pumped last year with new finds, while European rivals failed to do so, but the underlying performance of both reinforced fears the industry is short of attractive exploration opportunities. U.S. oil firms mainly relied on acquisitions to achieve large reserves additions in 2005, and Europeans may have to follow their lead in future if they want to halt an erosion of their asset bases.

Investment bank Lehman Brothers estimates that excluding acquisitions, the top U.S. and European oil and gas firms achieved a reserve replacement rate of only 82 percent. Oil firms usually target a rate of at least 100 percent, the level at which every barrel pumped is matched with a new find. A lower level suggests a firm’s asset base is being eroded and that it will struggle to grow or even sustain output in future. The industry’s 2005 result was an improvement on the 72 percent recorded for 2004, although below the average over the past 10 years of 118 percent. Western oil firms are shut out of the most attractive exploration acreage by Middle East governments and the areas they focus on are yielding smaller oilfields. This has prompted some, like U.S. oil majors Chevron and ConocoPhillip’s, to turn to buying reserves. Chevron’s takeover of rival Unocal enabled it to notch up an impressive 175 percent reserve replacement rate last year.

Excluding sales and acquisitions, the stellar 230 percent rate ConocoPhillips recorded shrunk back to 100 percent. Some investors are worried about this strategy because with oil prices above $60 per barrel, and increased competition from Chinese and Indian oil firms, the price of assets has soared, making takeovers an expensive way to grow one’s business. European firms were not so acquisitive and subsequently disappointed on the reserves front. London-based BP Plc, the world’s second largest listed oil firm only managed to add reserves equal to 95 percent of production, the same level as France’s Total SA. Royal Dutch Shell Plc, the third largest listed oil firm which many consider responsible for sparking investors’ obsession with reserves accounting when it cut its reserves estimates by over 30 percent in 2004, again disappointed. The Anglo-Dutch firm replaced only 67 percent of the oil it pumped with new finds, although this was up from 19 percent in 2004. Shell is looking to gas and non-conventional oil to bring its reserve bookings back on track.

The world’s largest listed oil firm by market capitalisation, Exxon Mobil, managed a healthy reserve replacement rate of 112 percent last year, mainly on the back of gas projects. But the heavy investment necessary in gas liquefaction plants and tar sands conversion equipment mean such operations have historically offered lower returns than oil projects. Oil executives say the apparently poor performance at adding new reserves in the last two years is partly due to the accounting treatment of “production sharing” contracts (PSCs).PSCs, which are increasingly common between oil companies and resource holders, involve oil firms receiving payment, in the form of oil, for their exploration and development costs and a pre-agreed share of profits, rather than ownership of, and full upside from, oil and gas fields.

Iran oil customers hang tight for now

March 17, 2006. Nippon Oil Corp.’s decision to ease out some Iranian crude due to rising political risks has rattled customers of the world’s fourth-biggest oil producer, but is unlikely to be followed by a wave of defections. Several small Japanese buyers said they were under corporate pressure to scale back imports as Iran’s rating as a stable supplier is called into question amid the ongoing dispute with the West over its nuclear aims. But refiners across the region said they were not contemplating similar action.  The move highlights the difficulties Iran may face in finding new markets as Tehran lags other producers in investing in overseas refineries, locking in future demand. Japan’s top refiner Nippon Oil would trim Iranian crude imports by 15 per cent this year due to growing country risks. It said it would buy less from Japanese trading houses, not reduce its own direct contract supplies.

The 22,000 barrel-per-day cut (bpd) is just half a percent of Japan’s total imports. However, the ramifications would be huge if other oil firms also turn their back to Iran, which many traders fear could cut off supplies if faced with sanctions by the U.N. Security Council over its atomic programme. With oil supplies expected to remain tight until new oilfields come onstream over the next few years, however, few customers appear ready to risk upsetting Tehran by cutting imports now, particularly with few alternatives at hand. National Iranian Oil Company (NIOC) said no other companies had reduced volumes due to the nuclear issue. Asia takes about two-thirds of Iran’s 2.4 million-bpd of exports, the rest flowing to Europe, Africa or Latin America. Fears of the nuclear dispute spilling into the oil trade have lifted the risk barometer to its highest since the Iranian Revolution in the late 1970s — the last time Iranian crude flowed into U.S. refineries — or the Iran-Iraq war of the 1980s. Surprisingly, Nippon Oil said it was hoping to boost crude imports from Iraq — long considered the least secure in the region — to limit dependence on Iran.

If enough customers gave up on Iranian crude, Tehran could resort to selling cargoes on a short-term basis, as Iraq did briefly after the U.S. invasion in 2003. While few see that happening yet, the shift in perception has been stark. They may become a supplier of last resort. Other major Japanese refiners would maintain their imports from Iran, which is Japan’s third-largest oil supplier, at a steady pace this year. About a quarter of Iran’s exports go to Japan.

Pak to attract $37-40bn FDI in energy

March 16, 2006. Pakistan is trying to attract $37-40 billion in foreign direct investment (FDI) in the energy sector to offset looming energy shortages as a result of 10 per cent annual increase in energy needs. The government had initiated a soft campaign to attract direct investment for seven energy projects. These projects are estimated to be completed in five to seven years. This will be in addition to the ongoing efforts to attract investments in the oil and gas exploration sector and development and privatisation of energy sector units, including oil and gas and power generation and distribution. The government was offering foreign investors to finance its $3 billion plan for import and supply chain of liquefied natural gas (LNG), enabling the country to meet fast approaching energy shortfalls. The government, believed that LNG would be vital to fill the gap in energy supply between 2007 and 2011-12 when pipelines for gas import might start functioning after the total energy consumption increased from the current 55 million tons of oil equivalent (MMTOEs) to over 80 MMTOEs in 2011-12.

Iran may ‘review’ oil contracts if faced with UN sanctions

March 14, 2006. Iran may review some of its contracts with foreign oil and gas companies if the United Nations Security Council imposes sanctions on the Islamic Republic over its nuclear programme. European energy companies, including Royal Dutch Shell Plc, Statoil ASA and Japan’s Inpex Corp., are already facing reduced profits in Iran as administrative delays, technical glitches, tough contract terms and Iran’s economic isolation due to existing US trade sanctions hamper development. US companies are barred by law from investing in Iran’s energy industry. The Security Council is expected to hold its first meeting on the issue this week.

IEA cuts world oil demand forecast on high Asia price

March 14, 2006. The International Energy Agency, an adviser to 26 oil-consuming nations, cut its estimate for this year’s world crude demand growth because high fuel prices are curbing consumption in parts of Asia, including Indonesia. The forecast for growth in demand was lowered by 340,000 barrels a day, to 84.74 million barrels a day. World consumption is now expected to increase by 1.49 million barrels a day, or 1.8 per cent, less than the 2.1 per cent predicted last month in its previous report. The expected demand for Opec’s crude oil will average 27.7 million barrels a day during the second quarter of this year, and 29 million barrels a day for all of 2006.

BP makes $3 bn trading oil, gas & power

March 14, 2006. BP Plc made $2.8 billion from trading oil, gas and power derivative instruments on international financial markets last year, up $800 million from 2004. The world's second-largest oil company made a net gain of $1.55 billion from trading oil products and derivatives and $1.31 billion from dealing in natural gas. The company lost $64 million in trading power derivatives. Investment banks, trading firms, oil companies, and increasingly hedge funds are active in using oil and gas derivative instruments and cargoes to exploit arbitrage and speculative opportunities. Oil companies also use the spot markets to balance volumes at different levels of the supply chain. BP's large production and refining base helps it take advantage of swings in oil and gas prices, such as the more than 30 percent rise in Brent crude last year compared with 2004.

Power

Utilities to build nuclear plant

March 17, 2006. Duke Power Co. and Southern Co. have tentatively selected a site in South Carolina for a nuclear power plant, which would be one of the first ordered in the United States in more than 30 years. Duke Power estimated the cost of building the new plant to be between $4 billion and $6 billion. The utilities expect to file an application to build the plant with the U.S. Nuclear Regulatory Commission in late 2007 or early 2008. The companies will decide later whether to actually proceed with plant construction in Cherokee County, S.C. The site is the same one where Duke Power started constructing a nuclear plant in the 1970s. The project was abandoned in the 1980s when load projections were lowered. Duke has said previously a new nuclear plant will feature two Westinghouse Advanced Passive 1000 reactors. Each reactor is capable of producing about 1,117 MW. Duke Power also was considering making early site-permit applications for two other potential nuclear plants, including one in North Carolina. That one would be in Davie County, about 50 miles northeast of Charlotte. Another South Carolina site under consideration for the early site-permit application is adjacent to the utility's nuclear plant in Oconee, S.C.

Moscow ‘s Mosenergo starts power plant construction

March 16, 2006. Moscow power utility Mosenergo starts the construction of a new thermal power plant, TETs-21. With a capacity of 450 MW, it will be the second largest power plant in Moscow. The project is part of the program to develop and modernize Moscow's energy system in 2006-2020. 2,100 MW of additional power capacity is expected to be put into service by 2010.

Nepal to import electricity from India

March 19, 2006. Nepal will import 70 MW of electricity from India. Nepal has a power exchange agreement with India for up to 150 MW, less than half of which has been exchanged so far. Negotiations are in the final stages to import 70 MW of additional power from India. The import of 20 MW from Bihar Electricity Board is expected to take place very soon. Import of another 50 MW will take place next year from West Bengal. Nepal is currently facing a major power deficit of 1.3 million units, making load shedding unavoidable for hours. The total demand of power is 8.2 million units in the country.

B’desh small power plant project shelved

March 20, 2006. The government has shelved its plan to set up small power plants of 10-30 MW halfway in course of its tender process and decided that barge and trailer mounted power plants would be set up on rental basis and PDB will have to buy electricity at a higher rate from those. The decision for dropping the small power plant project was taken as the government felt that it would take about 18 months to set up the plants but its term will expire after seven months. The Power Development Board (PDB) to initiate the process for inviting tender for setting up barge or trailer mounted power plants in selected areas where the small power plants were supposed to be set up. Intending entrepreneurs would set up the barge and trailer mounted power plants on build, own and operate basis and the PDB would purchase power from the plants.

The government in December last invited applications from interested entrepreneurs for participating in the tender for setting up 10 small power plants. The decision for setting up 10 plants were taken by rescinding another decision for setting up 23 small power plants of 10-50 MW over allegations of politicisation of tender procedure in August-November last year. Earlier, the government in 2004 also invited tender for setting up power plants of 10-30MW but later shelved the project without assigning any specific reason. A total of 40 applicants were selected few days back for participating in the tender process of 10-30MW plants from around 70 bidders who took part in the pre-qualification process. The meeting decided that the criteria for setting up these plants would be different from the criteria set by PDB earlier for setting up its plants at eight other areas for which the Board had invited tender. PDB had earlier invited tender for setting up barge and trailer mounted plants at Bogra, Thakurgaon, Shahjibazar, Shikalbaha, Kumargaon, Rajshahi, Fenchuganj and Khulna from where PDB would purchase power for 15 years. The PDB has accepted offers of three companies for Bogra, Thakurgaon and Shahjibazar plants from where PDB would purchase power at a higher tariff. The rate of power tariffs already fixed are Tk 10-12 per unit for diesel-run Thakurgaon plant, Tk 3.1 for gas-run Bogra plant and Tk 2.63 per unit for gas-run Shahjibazar plant. The rates are higher than the power generated by the PDB’s own plants. The Committee has decided that the PDB would purchase power from plants to be set up at 10 areas for two years. The high-powered committee also directed that the plants be set up by two months so that these plants start production before the next general election.

US plans to turn coal into liquid fuel

March 20, 2006. The Pentagon is trying to persuade investors and the energy industry to embrace an 80-year-old technology to turn coal into liquid fuel to power planes, tanks and other battlefield vehicles. Officials have been meeting with energy companies and state government officials to sell them on the idea. Military researchers have been testing fuel produced by the process to make sure it is suitable for military vehicles. The military is worried that political pressure or terrorist acts could cut the flow of oil from the Middle East or hurricanes or terrorists could destroy US refineries. There are roadblocks. Building coal-to-fuel plants is expensive possibly up to $5 billion (Dh18 billion). But then there is a coal lot of it. The Middle East has about 685 billion barrels of oil compared with 22 billion barrels in the United States. However, there is enough coal in the United States to produce 964 billion barrels of fuel.

China makes US offer on energy

March 18 2006. China is willing to work with the US on future oil, gas and renewable energy projects, as well as on global energy security. In the field of energy, China and the US are not competitors. China stands ready to co-operate with the US and other countries on the basis of equality and mutual benefit.

Libya signs nuclear research deal with France

March 16, 2006. Libya and France signed an accord on peaceful nuclear research, the first deal of its kind since Moamer Kadhafi abandoned efforts to build weapons of mass destruction in 2003. This accord represents a qualitative leap in relations between the two countries and proves that Libya has transformed its weapons of mass destruction into constructive weapons.

Suzlon Energy to invest $60 mn in China

March 18, 2006. Wind energy major, Suzlon Energy Ltd (SEL), would invest $60 mn (Rs 1.35 mn) in China for setting up an integrated wind turbine generator (WTG) manufacturing facility. The facility will have an annual production capacity of 600 MW. It is being set up at Tianjin. The investments would be made through SEL's Chinese subsidiary, Suzlon Energy (Tianjin) Ltd. China's Renewable Energy Law, which came into effect from January 1, 2006, is one of the largest state-sponsored commitments toward renewable energy in the world. It had also bought Belgium-based Hansen, the world’s second largest maker of wind turbine gearboxes, for $565mn (Rs 25.02 bn). This is the second largest foreign corporate takeover by an Indian company.

Oil Ministry opens National Bio-fuel Centre

March 14, 2006. The Petroleum Conservation Research Association (PCRA), an organisation under the Ministry of Petroleum and Natural Gas, has opened a National Bio-fuel Centre, which disseminates information regarding different activities on bio-diesel. The bio-diesel industry is at a nascent stage and the cost of production of bio-diesel would vary for different producing units. Oil marketing companies (OMCs) have offered to purchase the bio-diesel at the delivered price of Rs 25 per litre. This will be done at specified locations effective from January 1, 2006 for a period of six months, considering this to be the viable price for mixing bio-diesel with diesel and selling the mix in the market. This price is considered viable for producers of bio-diesel and comparisons with imported fuel would not be appropriate. The Ministry of Rural Development is the nodal Ministry for the proposed National Mission on bio-diesel, being set up with focus on large-scale plantation of jatropha cultivation. A detailed project report (DPR) on the National Mission has been submitted by that Ministry to the Planning Commission. The Planning Commission has given `in principle' approval to the DPR on demonstration phase estimated to cost Rs 1,286 crore ($290 mn) over a period of five years.

Germany moves ahead with major wind project

March 16, 2006. Germany has approved a second offshore wind energy project in the Baltic Sea with 330 MW capacity. The German authority, whose full title is Bundesamt fuer Seeschiffahrt and Hydrographie, has already approved nine projects in the North Sea and another called Kriegers Flak in the Baltic Sea. It is also processing 31 more applications for wind parks and transmission cables in the zone outside the 12 sea-mile border off the northern German coast. Germany's first North Sea wind park called Butendiek is expected to come on stream next year and a total 3,000 MW offshore wind power capacity may become operational by 2010 if project firms secure finance and overcome tough environmental rules. Onshore wind capacity has been mostly exchausted with 17,000 MW in place.

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