Energy News Monitor I Volume I, Issue 51

Baku-Tbilisi-Ceyhan Pipeline: Oil or Politics

The ceremony of commissioning the Azerbaijani section of the new Baku-Tbilisi-Ceyhan (BTC) pipeline again drew the attention of analysts to the project. Moscow did not support the idea of the pipeline but did not interfere with it either, though it had said that it would not provide oil to it. Sergei Grigoryev, vice-president of Transneft, had said that each state had an inalienable right to build what it needs. I would add, even if the project were unprofitable. Baku cannot supply as much oil as the new, highly expensive pipe from the Caspian to the Mediterranean can pump. Nobody is talking any more about the allegedly giant underwater oilfields on Azerbaijan's shelf. The truth is that the bulk of oil is concentrated on the eastern, Kazakh, coast of the sea. The competition of oil companies for transportation routes, which is always tough, has never been so politically loaded as in the case of the BTC, described as the main geopolitical project of the U.S. in the former Soviet states. The late president of Azerbaijan Geidar Aliyev had said that the pipeline would pump oil in one direction and politics in the other. Oil has not started flowing west yet, but Georgia, a member of the project, has been shaken by a pro-American revolution.   Americans spent through the nose to create the first stage of the Great Oil Road, laying pipes by a route bypassing Russia, which, as it grew stronger economically, is making public its view of developments in the former Soviet states, in particular on its southern borders, increasingly often. But will this pipe lower the transit potential of Russia?  

 

The new supermodern ports on the Baltic Sea, the upgrading of the Baltic Pipeline System to 60 million tons this year, and the nascent construction of pipelines in Russia's European north and the Far East will guarantee Russia a long geopolitical transit life in Eurasia.   The rerouting of Azerbaijani oil from Novorossiisk to the new pipe was hardly noticed, because it accounted for a mere 1% of Russia's oil exports. Baku says openly that it would like Russian oil companies to become its clients; it needs them to ensure the BTC's estimated capacity of 50 million tons a year. Besides, the capacity of the Russian pipe monopolist, Transneft, has been larger than the oil output for a second year running, according to its president Semyon Vainshtok. The production of oil is lagging behind the construction and modernization of pipelines and ports, though this year Transneft plans to increase export deliveries by 16% to 255 million tons.   There will be a surplus of pipe capacities in the future, and so Russia does not plan to change export routes. A spokesman of LUKoil, which works energetically on the Caspian shelf, told RIA that the current rates and the absence of "lines" for Transneft's pipe suit his company. Rosneft and other oil majors do not plan to change export routes either.   Russia plans to complete the construction of an alternative route to the BTC, from Burgas in Bulgaria to Alexandroupolis in Greece, bypassing the Turkish straits. It will be more profitable than the BTC: its length is slightly more than 300km (1,767km in the case of the BTC), its throughput capacity is 35-50 million tons (50 million) and it will cost about $700 million (some $4 billion). With the completion of this pipe, tankers with Russian oil will no longer have to spend weeks in the Turkish straits.   Baku thinks that the Kazakh oil can "save" the BTC, to a degree. President of Kazakhstan Nursultan Nazarbayev was the highest foreign guest at the commissioning ceremony and expressed interest in the pipe, but his republic will not hurry to sign a contract. This proceeds from the recent statement by Lyazzat Kiinov, deputy minister of energy. He said that his country had an operating project Aktau-Baku and hence the new pipe would be filled exclusively by Azerbaijani oil. Kazakhstan will ponder participation in the BTC project only when the new pipeline to the Mediterranean is completed. What effect would it have on the Transcaucasus?

 

Though there is not enough oil for the pipe so far, the aggregate capital of companies in the BTC consortium is $1 trillion, which makes the pipe an instrument of powerful political influence in the region. This is the opinion of Eduard Agadzhanov, of the Armat Center of Democratic Development and Civil Society (Armenia). In view of the unsettled Armenia-Azerbaijan conflict over Nagorny Karabakh, the powerful U.S. assistance to Baku is radically changing the geopolitical situation in the region.

 

A Glimpse of Countrywise Electricity tariffs

 

(In US cents/kwh)

Country	Industry	Domestic
India	7	3
Belgium	4	13
Canada	3	5
Chinese Taipei	6	8
Germany	5	12
Sweden	3	8
Japan	16	23
S. Korea	6	7
Mexico	5	7
New Zealand	2	6
Portugal	6	11
Spain	5	12
United Kingdom	5	10
United State	4	8

Source: IEA

Power Sector Reforms: Digging Worries, no Solutions?

 

PREAMBLE:

The National Electricity Policy announced in February 2005 has written much about what went wrong with power sector reforms in India, but what is missing in the policy is how to achieve the desired goals. It is necessary to note that during the past 14 years, the Ministry of Power (MoP) has produced several policy documents and issued numerous amendments, but it has failed to make any significant improvements in the power sector. The new policy is another example that the ministry is not yet ready to learn from its own mistakes. The policy uses language such as “concerted efforts would be required for restoring the financial health of the sector,” “all efforts will have to be made to improve the efficiency of operations in all segments of the industry,” “efforts would be made to ensure that the subsidies reach the targeted beneficiaries in the most transparent and efficient way,” etc. to address important issues. What specific ‘efforts’ would be made, by whom the efforts would be made, when and at what cost are left unanswered.

MoP has conveniently passed on the responsibility for most targets in the new policy to the state electricity commissions (SERCs), which are in their infancy and short of capacity to undertake such tasks. From issuing grid codes, establishment of transmission charges for ensuring open access, framing regulations for grid-interconnected for captive generators and segregation of technical and commercial losses to implementation of availability-based tariff in state levels, there are about 15 complex tasks that the SERCs are expected to carry out in the next 3 to 24 months. The existing 18 state electricity regulatory commissions in the country may not be able to complete these tasks that are highly technical in nature within the stipulated time. As envisaged in the Electricity Act, Regulatory Commissions Funds to build institutional capacity for SERCs may be established on a priority basis to equip them to handle the assigned tasks.  

The policy aims to ensure availability of 1000 units of electricity per capita by the year 2012 for which new capacity addition of more than 1,00,000 MW is planned by 2012, whereas the average achievement during the previous five-year plans was far below the target and it took five decades for independent India to build 1,00,000 MW. The new policy admits that coal would continue to remain the primary fuel for electricity production, but fails to list measures to be taken to ensure adequate supply of coal or alternative fuels to meet the growing demand for electricity. Dependence of the power sector on coal can be measured from the fact that 447 out of the 365 billion units of electricity generated in 2003-’04 came from thermal plants running on coal. Out of 352 million tones (mt) of domestic coal produced, 265mt was consumed for electricity generation. Even if coal production capacity increases, there will be a shortfall of 50-100 mt in the desirable GDP growth scenario.; the situation therefore calls for integral planning of new power projects in coordination with augmentation plans for coal production, import of coal or alternative fuels, development of port facilities/LNG terminals, storage facilities for fuels, logistics of fuel transportation by rail/road/pipelines and development of power transmission corridors. The Electricity policy also calls for a time-bound programme to be drawn up by the SERCs for segregation of technical and commercial losses through energy audits, which is a very important step towards reduction of T & D losses. A large number of states have been reporting losses of over 40 per cent in the recent years which is unsustainable. The policy urges the state governments to prepare a five-year plan with annual milestones to bring down these losses to best international practices by 2012.

Average T & D losses in utilities in developed countries
Technical losses in high voltage transmission system	2-3 per cent
Technical losses in the distribution system	2-4 per cent in urban areas 4-6 per cent in rural areas
Commercial losses	below 2 per cent

Increases in commercial losses, normally on account of unauthorized connections, drive the technical losses exponentially, as the distribution system is not equipped to handle that extra load. The direction for rural electrification in the new policy is also flawed and therefore the “Power for All by 2012” programme as proclaimed in the policy still maintaining that all villages will be electrified by the end of the Tenth Plan is difficult to believe. The policy of Open Access and Competition in the Market Place for bringing captive generation capacity into the grid by creating an enabling regulatory framework through open access guaranteed by the Electricity Act, thereby establishing transmission charges to promote competition amongst the generating companies seems, in its present form,  to be strengthening the muscles of a few middle men only who have not made any investments in the industry, rather than providing cheaper power to the end-user. Ensuring recovery of cost of services and targeted subsidies, as emphasized upon in the National Electricity Policy would require high up-front investments to reach rural customers against small revenue flows. Hence the subsidy programme has to be designed to ensure that subsidies are transparent, targeted and temporary which will improve access to electricity for the poor while not seriously distorting the energy markets.    

PANACEA OF REFORMS:

In order to improve the health of SEBs, the Government of India is encouraging the organizational restructuring of the power sector, namely the State Electricity Boards (SEBs), i.e., corporatization, unbundling, and setting up of regulatory commissions. However, these measures have proved insufficient in the states which have experienced them. Consequently, privatization has been promoted. But privatization itself has turned to be deceptive due to certain factors:

·          Both reforms and the bidding phase in the privatization process take time,

 

·          The investors do not want to commit financial resources due to lack of information and guarantees on both the means, and the latitude, then they will have to internally restructure.

The poor financial and technical condition of the Indian State Electricity Boards is widely acknowledged. There are fewer consensuses on its roots:

I.      Low tariffs but also cost inefficiency have resulted in the financial distress of SEBs; subsidies through undercharging of the agriculture and domestic sectors have increased from the 1980s, primarily due to local political decisions. The ratio of average tariff to cost of supply is equal to 0.76. On the SEBs’ efficiency side, relative laxity in the metering of energy, and high levels of technical and ‘non-technical’ losses, are noteworthy. The latter include include thefts, bribing, unmetering as reflective of gross corruption. World Bank-appointed consultants assessed the total level of losses at 40-50 per cent over India. With this level, the final average cost is at least twice the generation cost. Non-technical losses would amount to 20-30 per cent. This high level of energy loss contributes to the commercial losses of the SEBs. Its technical part shows that the investment share between generation and network has been far from optimal. Similarly, low operation performance (poor plant load factor, high rate of burnt transformers) shows the low expenditure in maintenance.

II.      The low cost performance of SEBs is linked with political interference; they have not been so much ‘poorly managed’ according to a stated objective of economic efficiency, than managed according to objectives other than they were actually given. The SEB’s style of functioning is administrative and not the way firms are run.

III.      Looking for cost efficiency makes sense only within firms. Therefore, if there is a will to address the cost efficiency of SEBs, they have to be ‘enterprised’, i.e. turned from administrations into firms not only in their status, but also in their decision-making. Reforms need to enable SEBs to look at cost efficiency without any external discretionary power.

IV.      Beyond corporatization and the setting up of regulatory commissions, the promoters of reform also argue that unbundling or de-integration of the former SEBs into generation, transmission and distribution companies is to be promoted. The aim-apart from making companies easier to privatize-is to assess the results and the responsibilities among the various activities by de-integration. But even if structures are unbundled, what really matters is that each of them becomes actually enterprised, which is not guaranteed under de-integration only. Structural reforms undoubtedly constitute a first step towards enterprisation. However, after them, the latter is still incomplete. Privatization is one way of doing it. Public reform, if well designed and supported by some policy makers, could be another.

V.      The public debate on power sector reforms has to change its orientation. The clichéd opposition between the public sector and privatization needs to be refined. What matters is not that objectives are different from public to private, but the way decisions are enframed in a structure is largely determining. Both attempts at reforming, either within the public sphere or with the help of the private sector, show bottlenecks. Let us focus on public reform. From the work of already existing regulatory commissions, it appears that regulation is essentially based on reduction in energy losses. Political rationality might be to accept a lower pace of non-technical loss elimination than expected by commissions, and hence lower SEB revenue, if this provides political returns. This could be strengthened by the remaining discretionary power of SEBs. There is therefore an assumption that public reform will be less efficient in tackling losses than private reform, or at least that there will be a delay, this delay being costly. As experience of successful public reform is lacking and as the contents of a credible public reform are still to be defined and proved effective, this is still a conservative assumption. So the main bottleneck of public reform is linked with the difficulty of escaping an ancient system. On the other hand, privatization can also present difficulties. A partial enterprisation implies incomplete information about the future of the privatized organization, either because of a weak information system, or because of a weak guarantee that independent management is possible. It leads to asymmetric information between the seller and potential buyers, as well as among various potential buyers, that affects the level of the bid. This is the main bottleneck of private reform in the short term.

The systematic approach to the administrative nature of SEB management shows that classical tools of industrial economics which are linked with the study of the firm are inadequate when it comes to understanding SEBs. This approach enables one to find consistency, if not predictability in the actual running of SEBs. Consequently, it helps to evaluate what reforms are required in order to turn SEBs into firms.

To be continued...

Japan to buy more Gas from Sakhalin II

 

 Sakhalin Energy, the company that operates the Sakhalin II project providing natural gas to Asia, has almost completed the signing of all long-term, natural gas contracts, which include an increase in sales of liquefied natural gas to Japan.   Sakhalin Energy (SE) said that a contract had been signed with Toho Gas to increase annual liquefied natural gas deliveries by 0.2 mn mt over the course of the next 20 years. This is the third commercial success for SE in the last seven days.  Japan will receive 0.8 mn mt more liquefied natural gas per year (over $3 bn).   SE signed even more lucrative contracts with Tokyo Gas (1.1 mn mt of liquefied natural gas over 24 years), Tokyo Electric (1.5 mn tons over 22 years), Kyushu Electric (0.5 mn tons over 22 years), Baja Mexico (1.6 mn tons over 20 years), and Kogas (1.5 mn tons per year with a possible additional 0.5 mn tons).  

 

The Japanese buying frenzy is motivated by projected mid-term Asia-Pacific liquefied gas price hikes. Experts think that liquefied natural gas will cost 75% more on Asian markets in five years. These estimates hinge on greater U.S. and European gas demand. North American liquefied gas futures now cost 50% more than those in Asia. Wholesale Asian buyers spend $234 per metric ton of liquefied natural gas (minus delivery costs). The same amount costs $345 per ton in the United States. Analysts think that a ton of liquefied natural gas will cost $400-430 per ton by 2010.   The Sakhalin II project calls for developing the Piltun-Astokhsky and Lunsky deposits on the northeastern shelf of the island. The latter mostly contains gas, gas condensate, and oil. Both deposits together contain over one bn barrels (150 mn tons) of oil and more than 500 bn cubic meters of natural gas. 

Russia-India Energy Dialogue Continues

This March, state-owned Technopromexport (TPE) celebrated 50 years in the energy-construction business. Under the Soviet state-planned economy, the USSR readily provided extensive technological and economic assistance to politically friendly governments. TPE was in charge of energy construction sites abroad, notably in India, under inter-governmental agreements and contracts. In the late 1960s, customers grew increasingly wary of this form of assistance, which made TPE to take a proactive approach to cooperation with Indian organizations. Technopromexport’s first Indian projects - the Bhakra and Lower Sileru hydroelectric and Neyveli and Obra thermal power plants - had a total output of over 1,600 MW, and still receive industry awards for high productivity; the Neyveli site has even got several government decorations. In economic terms, the TPE-built Vindh'chal still remains one of India’s best thermal power plants. In late 1970s and early 1980s, Technopromexport became a developer providing only ready-to-operate energy installations. Today, TPE has a unique database and network of contacts with world producers of generating equipment and construction companies specializing in energy installations. As part of the reform of India’s energy sector in recent years, the government has enacted new laws (Energy Conservation Act 2001 and Electricity Act 2003) and new short- and long-term programmes for the entire electricity industry and for its separate sectors (Accelerated Power Development and Reforms Programme 2000; Rural Electricity Supply Technology Mission 2002; Mission 2012: Power for All 2003; 50,000 MW Hydro Initiatives 2003). 

According to the January 1, 2005, report of the Central Electricity Authority of India - currently the world’s sixth largest generator of electricity after the U.S., China, Japan, Russia, and Germany - proven national generation output amounted to 114,739.80 MW, of which thermal power plants accounted for 79,451.45 MW (69.2 per cent); hydroelectric power plants for 30,080.23 MW (26.2 per cent); nuclear power plants for 2,720 MW (2.37 per cent), and others for 2,488.13 MW (2.17 per cent). By 2012, the Indian government has pledged to fill the gap between supply and demand for electricity by putting into operation an additional 100 GW of generating facilities through a number of government approved industry specific programmes, some classified as “mega-projects” and accordingly enjoying a high-priority status. A hydroelectric mega-project should target at least 500 MW in output; the bottom line for a thermal one is 1,000 MW. Once classified as participants in a mega-project, Indian companies are relieved of all tariffs for imported equipment, of all taxes for the next 10 years, and, importantly, get a great deal of state support. Therefore, the top priority for India’s National Thermal Power Company remains to find trustworthy partners who could build world-class energy sites.  With India so ambitious regarding its national energy sector, TPE began to promote its services and maintenance aggressively on the Indian market. In March, TPE also successfully sealed a major contract for the 1,980-MW Bahr thermal power project, also known as the “Steam Island Project,” worth about 20 billion rupees (about $4.5 million). The power plant will comprise three 660-MW units featuring supercritical steam technology to heat the steam to super-high temperatures. This is done to raise efficiency, which traditionally used to depend in linear relation on the output: the more powerful the plant, the higher the efficiency. However, the supercritical steam technology provides high efficiency even if the output is not that large. Technopromexport has an extensive record of work with such equipment, for instance, at the very successful 1,600 (2x800)-MW Suizhong thermal plant in China. In November, TPE had to beat off powerful rival bidders including South Korea’s Doosan and international consortium BHEL-Alstom to win the Bahr tender. The Russian company built its bid on a competitive price as well as other terms and conditions.

TPE’s record of successful bidding is extensive: in the central Russian city of Ivanovo, Technopromexport won a tender for a steam-gas power plant (325 MW); in Libya, it was awarded the contract for the Western Tripoli plant, increasing its portfolio by a third in the last three years to $2 billion. As a state-run company, Technopromexport has always remained fully accountable for all its contractual obligations, while at the same time foreign contractors see it as an important link in a governmental chain of top-down cooperation, which helped other countries put projected sites into their national development plans. The greater part of the Bahr project is Russian - Russian companies provide from 65 per cent to 70 per cent of all necessary equipment, while the rest comes from European and Indian producers. Indian contractors will also provide logistics, local transportation, installation, and other auxiliary services. In total, local contractors get up to 15 per cent of the whole contract.  Technopromexport also acts as a gate through which many Indian companies tap third-country markets as subcontractors and subproviders for various energy projects run by TPE. Further dialogue with Indian partners is all the more attractive for TPE because India is clearly willing to build more of what has been the backbone of Russian power generation industry from its early days - high-power (800-MW to 1,200-MW) supercritical steam turbines. TPE is ready to bring hi-end power generation technology to the Indian market, working hand in hand with its Indian partners.

India’s Reforms in the Hydrocarbon Sector

 

What Has Been Accomplished?

What Remains to be Done? -VIII

 

……continued from issue 50

 

What was achieved continued….

 

In the downstream segment, the Administered Price Mechanism (APM) introduced distortions in the market that have had far reaching consequences on issues ranging from profitability of public sector units to oil dependency of the economy.  Strangely much like other market distorting policy decisions such as free power to farmers, whose origin can be traced to an unrelated issue, so can the origin of APM.  In the early 70s, the Shipping Corporation of India (SCI) took a loan from the World Bank to purchase oil tankers. The World Bank then recommended a 'cost plus' pricing formula to SCI for freight calculation. The same principle was introduced in the name of 'retention concept' to crude and petroleum products pricing in 1976.   What long term objective did this policy decision aim to serve is unclear but there were consequences nevertheless.

 

The policy to price indigenous crude on operating cost plus 15 per cent post tax return on capital employed as well as that to price petroleum products on the basis of operating cost plus 12 per cent post tax on net worth made PSU refiners and oil marketing companies inefficient and unfit for real competition in the post APM era.  However the retention pricing concept helped to maintain the creditworthiness of the oil sector PSUs which protected multilateral creditors. 

 

The other important component of APM, the 'cross subsidisation mechanism' succeeded in establishing the dominance of the oil industry in the energy sector.  In the downstream segment, policies adopted by the government - particularly pricing policies - made the economy completely dependent on petroleum products and to a certain extent successfully replaced/barred entry of other alternative energy sources such as natural gas. 

 

Cross subsidised petroleum products competed with other energy sources like coal and made inroads into its domain.  Low priced kerosene replaced vegetable oil for illuminating lamps and subsidised LPG replaced coal and wood as in cooking.   Small, energy inefficient trucks used subsidised diesel to compete with railways in freight movement and systematically eroded its market share. Subsidised Naptha made the coal technology unviable for fertiliser production.  An elaborate distribution network complemented the skewed pricing policy thus consolidating the role of petroleum products in the Indian economy.  While India’s increasing oil import dependence is now being projected as the most serious energy security issue, the real issue is the vulnerability of the economy to oil price volatility. 

 

The Eighth Plan Document (1992-1997) highlighted the increasing role of oil in the Indian economy and recommended efficiency measures to curb oil use.  It provided Oil Application Ratio (OAR), the ratio of oil consumption in different sectors to the total consumption of oil in the country, as a measure of the importance of that sector in the consumption of petroleum products.

 

Oil Application Ratio

Source: Eight Plan Document, Volume II

 

In terms of OAR, the transportation and household segments were the largest users with relative share increasing over the years.  Even in terms of intensity of oil use or ‘Oil Use Ratio’ (defined as the ratio of oil consumption in that sector to total energy consumption in that sector) transportation and household segments show alarming increase.    There is no doubt that subsidies on kerosene, LPG and diesel were primary drivers of this increase.  

Oil Use Ratio

Source: Eight Plan Document, Volume II

 

Overall the share of oil in the total commercial energy consumption increased contrary to the recommendations of the Working Group on Energy Policy. Energy conservation and review of energy pricing were the two key policy areas that required attention in order to reduce oil dependency of the economy.  However most of the efforts in this direction did not produce the desired results. 

 

Team Energy ORF

 

Working group discusses plans to export electricity to China

 

Russia's working group on the development of the energy sector of the southern Far East held a meeting in Khabarovsk, discussing plans for Far Eastern electricity exports to China. The group dwelled on the plans to develop electricity generation and electrical grid facilities in the Amur Region, Maritime Territory, Khabarovsk Region, and southern Yakutia for the period of 15 years, given electricity exports to China and Korea can be raised in the future. Experts said the Far East possessing enormous prospected hydro resources could supply Northeast Asia suffering from power shortages with electricity without damaging domestic consumers' interests.   Scientists insist pursuing export-oriented strategies in the energy sector is important in the present circumstances. Whereas gross regional product grew by 28.8% in the Far East from 1995 to 2002, industries' electricity consumption rose by a mere 11% over the same period, while the share of power consumption in the structure of local production reduced two-fold, according to the Economic Research Institute, the Russian Academy of Sciences' Far East Branch.  

 

The reports studied at the meeting showed the plans to boost exports, including to China, could start being implemented even now. The initial phase will not require investment in new generating facilities. The now "locked" energy sources will only have to be released and more power lines built. Investment in power generation will be required in the event of boosting exports.   China's State Grid Corporation and the Federal Grid Company, part of the Unified Energy Systems Co., Russia's electricity giant, are drafting an agreement that will stipulate the volume and directions of electricity flow, other parameters, and cooperation terms and conditions. The draft agreement is being studied thoroughly in terms of Russia and the Far East's security and economic interests. The countries are expected to sign the agreement in Moscow in late June.

 

50 per cent of country’s coal reserves are estimated to be in Jharkhand and Orrisa (In Million tonnes)

Sates	Proven reserves	Estimated reserves
Jhakhand	35409	71864
Orrisa	14614	60988
Chhattisgarh	8771	39545
West Bengal	11383	27394
Madhya Pradesh	7513	18660
Andhra Pradesh	8091	16697
Maharashtra	4653	8414
Uttar Pradesh	766	1062
All India	91631	245693

Source: Ministry of Coal

NEWS BRIEF

OIL & GAS

IOC bags gas block in North Pars field 

June 14, 2005. Iran has decided to award a block to the Indian Oil Corporation-Petropars consortium in the North Pars gas field for its 9 million tonne per annum (mtpa) integrated LNG project. IOC will be amongst the few companies to be awarded a block in the first stage of development of the North Pars gas field. The reserves in the North Pars gas field are estimated to be 47 trillion cubic feet (tcf) of gas. IOC requires around 12 tcf of gas for its 9 mtpa LNG project. The total cost of the integrated LNG project is US$5.7 billion with IOC chipping in Rs 7,300 crore (Rs 73 bn). The project comprises five parts including a US$2.2 billion upstream project, to be developed by a joint venture between IOC and Petropars. IOC will have a 40 per cent stake in the JV with an investment of over Rs 4,000 crore (Rs 40 bn). The second stage of the LNG project entails a US$1.8 billion liquefaction facility to be set up by another IOC-Petropars JV with 60 per cent IOC share and an investment of Rs 1,500 crore (Rs 15 bn) by the Indian refinery major. The third stage involves a US$800 million shipping project where IOC’s share would be 50 per cent with an investment of Rs 550 crore (Rs 5.5 bn). This will be taken up jointly with leading international shipping companies. The fourth stage will involve setting up a regasification facility in India at a cost of US$600 million. The fifth and final stage includes putting up a 500 km regasification LNG transportation pipeline at a cost of US$300 million.

Extended exploration for Cairn in Rajasthan

June 13, 2005. British oil and gas major Cairn Energy has received an 18-month extension on exploration licence for the north and west of Rajasthan. This appraisal area incorporates the Bhagyam and Shakti oil fields as well as several structures requiring appraisal and intervening tracts of untested acreage. One such structure, the N-I, has been successfully tested by the N-I-2 well, which lies between the Bhagyam and Mangala fields. Also discussions with the central Government are going on regarding an application for an extension of the southern area of the Rajasthan block.

ONGC to complete redevelopment project

June 7, 2005. ONGC is set to complete the Bombay High North redevelopment project six months ahead of schedule in December 2005. The development is expected to lead to a spurt in the company's crude production beginning the fourth quarter of the current year. Production will increase further once redevelopment of Bombay High South is completed in 2006. Commissioned 30 years ago, Bombay High alone contributes 40 per cent of ONGC's crude production. Another 14 fields produce 35 per cent of the total. The remaining 100 fields contribute just 25 per cent. ONGC had launched a redevelopment project in Bombay High North and South in February and September 2001 respectively to restrict a drop in production as well as improve the recovery factor. The total project cost was estimated to be in the region of Rs 8,200 crore (Rs 82 bn). The redevelopment project was launched following a drop in production from 20 million tonne to 12 million tonne a year. The project is expected to improve the recovery factor by 4 per cent yielding an extra 76 million tonnes (mt) of oil and oil equivalent gas for a period of 20 years. Of the two fields, Bombay High South is the larger one and is scheduled to produce an additional 45.6 mt during its life. The total investment in the project is expected to be recovered in five years. Being implemented in phases, the project has already led to an increase in production from India's only large oil field. Following completion of the redevelopment project, the recovery factor from the field will improve from 28 per cent to 31 per cent. According to a rough estimate, every percentage increase in recovery will generate an additional revenue of more than Rs 3,000 crore for the company.

Gaz offers 1 mt LNG to Petronet

June 13, 2005. Gaz de France, one of the equity holders in Petronet LNG, has offered to bring 1 million tonne liquefied natural gas (LNG) from Iran’s South Pars field. Petronet is also trying to source additional quantities of gas from Qatar. Gaz holds 10 per cent equity in Petronet. It is offering LNG to Petronet out of its share of gas from Pars LNG. Gaz is the national gas company of France and is the largest importer of LNG in Europe. It has provided technical support to Petronet for the construction of LNG terminal. Petronet is currently operating a LNG terminal at Dahej in Gujarat for which it is buying gas from RasGas of Qatar. RasGas holds another 10 per cent stake in Petronet. Petronet LNG is planning to expand the capacity of its Dahej terminal from 5 to 10 million tonne per annum (mtpa) by 2008, while simultaneously going ahead with another LNG terminal at a cost of Rs 2,000 crore (Rs 20 bn) at Kochi in Kerala. The Kochi terminal would have a capacity of 2.5 mtpa. This terminal was planned along with the Dahej terminal but the company had been going slow on this project awaiting demand in the region to go up. The company plans to raise the capacity of Kochi terminal to 5 mtpa in future and the construction would be completed in two and half years. Petronet LNG, a joint venture of Indian Oil Corporation, Oil and Natural Gas Corporation and Bharat Petroleum Corporation and GAIL, had been negotiating with the Qatar government to provide additional 7.5 mtpa LNG beginning 2007. But most of the Qatar LNG capacity has already been tied up.

IOC bids for acquiring Turkey's TUPRAS refinery

June 9, 2005. Indian Oil Corporation has bid to acquire Turkey's giant petroleum refinery TUPRAS, which has a combined processing capacity of 27.6 million tonnes per annum. The company has submitted a letter of intent to the Turkish Privatisation Administration (PA) to acquire 51 per cent stake in TUPRAS, for which eleven other local and international oil firms are also in the fray. It is the second time that block shares of TUPRAS have been put on sale.

India in US$20bn LNG supply pact with Iran

June 14, 2005. India and Iran signed the final sales purchase agreement valued at US$20 bn for LNG supplies, the first consignment of which is expected to reach Indian shores by ’09. This is one of the largest overseas commercial deals signed by India. The contract price is estimated at US$3.51 per mmbtu. The contracted gas will be primarily used by the northern and western Indian markets to fuel power plants and manufacture fertiliser. Some quantities of this gas will also be used as non-polluting fuel for motor vehicles. The 25-year supply contract is tied up with the oil exploration interests of Indian oil companies, often referred to as oil-for-gas deal. India has been assured a 10 per cent stake in the Yadavaran oilfield and a 100 per cent stake in the Juffair field, in return for lifting assured gas supplies from Iran. India has also managed to build in a “pure supply deal” with Iran. This means that both Iran and India be liable to pay penalties either if Iran does not ensure timely supplies or India fails to lift committed quantities of gas. The two sides have also agreed to set up a joint monitoring committee to track investment commitments. Right now, Iran is making an all-out effort to woo foreign investments — both from Asia and the west — to muscle up diplomatic power against US threats. India's efforts to seal the entire deal for 7.5m tonne with additional stake in the exploration business will have to wait for some time. The contracted price of US$3.51 per mmbtu includes a fixed component of US$1.2 per mmbtu and a variable component of about .065 points linked to the Brent. The Brent price has been capped at US$31 a barrel. The price of gas at the Iran border works out to around US$3.21, to be delivered at US$3.51 per mmbtu after taking shipping costs into account.

GSPCL to buy gas from Reliance field

June 9, 2005. Gujarat State Petroleum Corporation (GSPCL), the country's only state government-run oil and gas major, plans to enter into an agreement with Reliance Industries to buy gas from the Krishna-Godavari field. The Rs 1500 crore (Rs 1.5 bn) GSPCL has been searching for gas sellers to meet its additional demand for 5 million metric tonne per annum (MMTPA) of gas. RIL expects to start commercial production of gas from KG in the later half of 2007. At present, it is meeting the demand for around 2.5 MMTPA of gas from Gail India(one MMTPA) and its own gas fields in Hazira (one MMTPA). It is meeting the rest of its needs from the Panna-Mukta Tapti fields. GSPCL has already agreed to supply gas to Torrent Power Generation Company's (TPGCL) upcoming 1000 MW mega power plant near Surat and GPEC's 1000 MW power plant near Bharuch. The Essar Group is also planning for a 1000 MW power plant in Gujarat. Meanwhile, GSPCL, which has been producing around 4,000,000 cubic metres of gas every day from its 24 wells in Hazira, has worked out a plan to start exploration and production of gas from eight more wells in the Hazira field. The new wells are reportedly filled with rich gas reserve. In the Hazira field, Niko Resources holds 33 percent operating interest with GSPCL holding majority 67 per cent operating interest. This will also require an additional investment as exploration and commercial production from each well will cost around US$3 mn. GSPCL has recently made oil recovery at wells near Dholka in which Gail is an operating partner while GSPCL has been producing 10 tonnes of oil per day from its oil fields on River Sabarmati flowing through Ahmedabad. 

ONGC commissions Mumbai-Uran trunk pipeline

June 8, 2005. The 504-km long Mumbai High-Uran trunk pipeline was commissioned by Oil and Natural Gas Corporation. The sub-sea pipeline will replace the existing pipeline that transports oil and gas from Mumbai offshore to the onshore process complex at Uran for further processing and supply. The pipeline originates at the MNW platform at a water depth of 72 m and touches the shore at the Uran landfall point.

Changes in oil prices may be few

June 14, 2005. The petroleum ministry wants to change the fortnightly price revision practice officially followed by the oil companies after the dismantling of the administered price mechanism. While in most advanced economies, petrol and diesel prices change daily, the ministry is of the view that change should not be fortnightly any more. The suggestion by the ministry to the Cabinet, also added that the revision should be either monthly or even quarterly since the fortnightly revision was “too frequent”. The fortnightly revision of petrol and diesel prices though officially remains on paper; it is not being followed in practice. Public sector oil companies are incurring about Rs 4.59 and Rs 4.97 a litre under-realisation on petrol and diesel, respectively, because they have not been allowed to change the retail prices since November though the price of the Indian basket of crude has risen more than 27 per cent during the period. Petroleum ministry said international oil prices might not significantly decline in the near future. The ministry also wants that the price band mechanism introduced last year be restored. 

Hiking investment limit of OVL

June 13, 2005. In tune with the ONGC Videsh Ltd's efforts to acquire equity in oil and natural gas assets abroad, the Standing Committee on Oil Diplomacy for Energy Security may recommend to the Union Government an increase in the investment limit of OVL to the range of US$100 mn. The board of directors of OVL is now allowed to take investment decisions up to US$70 mn (Rs 300 crore). The high profile standing committee was formed in November 2004 to evolve ways of reducing the country's dependence on imported oil. Though the Government had increased the investment limit from US$50 mn to US$70 mn last year, ONGC is of the view that such low investment limits have little relevance to the high value oil and gas sector. Since investments beyond the permissible limits need to be approved by the Cabinet committee, the company often loses time in taking a call on emerging investment opportunities. As part of its focus on enabling Indian oil companies to acquire oil and gas assets abroad, the committee is actively considering recommending the enhancement of the existing limit on OVL to a reasonable level. Currently, OVL owns equity in oil and gas assets in Vietnam, Sudan, Russia (Shakhalin-I) and Myanmar, and has recently drawn up an ambitious investment plan for the next two years. The company is currently negotiating for a number of deals in Russia, Iran, Venezuela, Ecuador, Cuba and Brazil. Overall, the capital expenditure for 2005-06 may cross last year's level of Rs 5,000 crore (Rs 50 bn). This is in addition to capital expenditure of over Rs 10,000 crore (Rs 100 bn) by ONGC in the domestic sector.

Iran LNG, natural gas to China 

June 12, 2005. India is seriously contemplating exporting part of its natural gas and LNG supplies from Iran to Asian markets particularly China. For natural gas, petroleum minister, Mani Shankar Aiyar has already discussed extending the Iran-Pakistan-India gas pipeline project to China with the petroleum minister of Iran, Bijan Namdar Zanganeh. Even for LNG, Indian Oil Corporation (IOC) has chalked out plans to export part of its share of LNG from Iran to Asian buyers including China, South Korea, Japan and Taiwan. IOC along with Petropars is putting up a 9 million tones per annum liquefaction plant in Tehran. It is estimated that there will be a demand-supply gap of about 99m cm/d (about 25m t/y) by 2010 in these countries. This will grow further in subsequent years. IOC has planned US$1.6 bn investment in executing an 9 million tones per annum integrated LNG project with an upstream and liquefaction component with Petropars of Iran. Gas will be sourced from one of the South Pars development phases and come onshore to the liquefaction facility.

OVL, GAIL on Azerbaijan hunt 

June 10, 2005. ONGC Videsh (OVL) and GAIL India are planning to enter into separate memorandum of understanding (MoUs) with the State Oil Company of Azerbaijan (Socar) for jointly undertaking oil and gas exploration in the Caspian Sea. As many 35 international oil and gas companies including British Petroleum, Stat Oil of Norway, Exxon Mobil, Encana, Shell and Unocal have their presence in this region. British Petroleum alone has committed investments of US$20 bn in undertaking various oil and gas projects in Azerbaijan. In addition to undertaking new projects with Socar, GAIL is keen to pick up a stake in the Shah Deniz gas and condensate development project in Azerbaijan, 8th largest energy project in the world. OVL, too, is interested in 5 per cent equity in the Azeri-Chirag-Gunashli (ACG) oil field with the present production profile of 140,000 barrels of oil per day. However, it will be difficult to accommodate any new company in any of the two producing assets. But co-operation in many other projects could be pursued jointly. The Shah Deniz gas field produces around 14 million standard cubic meters of gas per day (mmscmd) but more than half of this is being flared and Azerbaijan has to import about 12 mmscmd of gas to meet its domestic consumption. Besides other areas, there is a lot of scope for finding oil and gas in certain disputed areas in the Caspian sea.

Crude from Caspian via Azerbaijan 

June 10, 2005. Azerbaijan may soon become an important energy link for India in bringing crude oil and gas from the Caspian Sea region. India, which imported 95.9 million tonne crude and a little over 5 million tonne per annum of LNG during 2004-05, has so far not been able to source any crude oil or gas from the Caspian region due to absence of links with the major exporting ports there. Located about 1,600 km south of Moscow, the Caspian Sea region has emerged as a focal point for untapped oil and natural gas resources. In order to reduce its dependence on crude oil from the Gulf region and meet its quest for energy, petroleum minister, Mani Shankar Aiyar proposed accessing crude oil from the Central Asia and Caspian region using an Israeli pipeline. Mr Aiyar said the 254-km long Eilat-Ashquelon pipeline could be used for transporting east Mediterranean crude to the Red Sea, from where it can be shipped to India. Oil can be pumped from the Caspian region into the just commissioned 1,764-km Baku (Azerbaian) - Tbilisi (Georgia)-Ceyhan (Turkey) pipeline to reach the Mediterranean Sea from where it can be pumped into the Israeli pipeline for Very Large Crude Carriers (VLCCs) to pick up at Red Sea for transporting it to India. He said that there is immense possibility of US becoming consumers of Caspian oil so we are ready to pick up whatever Caspian oil is available on Mediterranean sea on competitive rates. The Eilat--Ashqelon pipeline links the Red Sea Port of Eilat with the Mediterranean Port of Ashkelon for around 30 years now. This is a reversible pipeline capable of transporting 40 million tonne per annum of oil. It has a storage capacity of 1.1 million tonne on the Eliat side of the pipeline and 1.3 mt of crude can be stored on the Ashquelon side.

India, Pak to carve out oil buyers' bloc

June 9, 2005. This is a different power game. India and Pakistan have jointly embarked on a new voyage in their quest for energy security. And in the process, the two energy-hungry nations may end up rewriting market rules and changing the region’s energy equations as collaborators in the great oil hunt. The world energy market has so far been dictated by a cartel of oil and gas-producing nations. Now join the game on the other side of the chessboard where buyers could settle the terms of the trade. India and Pakistan will seek to emerge as the new buyers’ block, the natural market for the region’s leading gas producers. India is the natural market for most of these gas producers... the assured market for gas producers such as Iran to monetise their resources. Where else can they get such volumes? After all, geography has placed India and Pakistan in proximity to the greatest gas reservoirs in the neighbourhood. India has already taken a lead in this direction by aligning with the largest consumers of the region — China, Japan and Korea. Taking Pakistan on board, India now seeks to converge the largest producers of oil and gas with the largest consumers in the region. The evolving buyers’ block would possibly be a force that even US may find hard to ignore. China’s move to source LNG — the country has contracted to bring in at least 10mt over the next 25 years — coupled with India’s own LNG deal for 5mt from Iran is already beginning to realign energy equations in the region.

India to build reserves for Iran pipeline

June 8, 2005. India will develop underground natural gas storage facilities to act as a reserve in the event of disruption in supplies through the proposed US$4.16 bn Iran-Pakistan-India pipeline. These facilities would be set up by state-owned Oil and Natural Gas Corporation (ONGC) and Gail (India) Ltd. The country would be able to fall back on these reserves, which would ensure supply security. These underground natural gas storage facilities would be set up through a special purpose vehicle (SPV). French consultants Gaz de France would assist in the project.

India shows interest in more pipeline projects

June 8, 2005. India has expressed interest in participating in the proposed gas pipelines from Turkmenistan, Iran and Qatar ‘not as alternative options to each other but for multiplying gas supplies. There had been a general realization that the three gas projects should be taken up because energy needs of the two countries would increase with the growth of their economies. Petroleum minister Amanullah Khan Jadoon briefed the Indian Petroleum minister Mani Shankar Aiyar on the Turkmenistan project and the Indian side expressed interest in it. The Pakistani side outlined the parameters of the proposed Gulf-South Asia pipeline project and India expressed interest in participating in it. The ministers reviewed the proposal for the Iran-Pakistan-India pipeline and agreed that the project would go a long way in meeting the energy requirements of the two countries. The Indian and Pakistani delegations also agreed to exchange information about financial structuring and other related issues to realize a safe and secure project. It was also agreed that a joint working group would be set up at the secretary-level. The group will meet regularly and report to the ministers to help them to take definitive decisions at the earliest. The two ministers agreed that the transnational pipeline projects should be given top priority as they carried substantial advantages for the two countries. They were of the view that the processing of pipeline projects should be accelerated given the substantial requirements of gas for the two countries. The Indian minister explained to the Pakistan side India’s requirements of gas and arrangements worked out by India. The Pakistani side presented in detail the position of demand and supply for natural gas in the country. While India’s unmet gas demand would be 300 million metric standard cubic meters of gas per day, Pakistan’s unmet demand would be 100 mmscmd more. So there is an aggregated gas demand of 500 mmscmd in India and Pakistan, to be met from imports. It, therefore, becomes necessary to explore all available sources of gas to meet the extremely large gas requirements of the two countries.

India, Pak to work together on three pipeline projects 

June 8, 2005. Pakistan President Pervez Musharraf endorsed the joint participation by India and Pakistan in executing transnational natural gas pipeline projects. The two sides have agreed to work jointly on the Iran-Pakistan-India pipeline project, the Turkmenistan-Afghanistan-Pakistan (TAP) project and the Gulf-South Asian gas pipeline project from Qatar to Pakistan, being extended to the Indian coast. Petroleum Minister Mani Shankar Aiyar indicated India’s interest in the Gulf-South Asian gas pipeline project and Mr Musharraf said Pakistan has no problems with India’s participation in that project. Mr Aiyar said that he would now take up our participation in that project with the Qatari authorities. So, for all three pipeline projects, the roadmap has been chalked out and the milestones are in place, he said. Mr Aiyar’s idea is to make TAP a TAPI (by extending this to India) and later UTAPI (by adding Uzbekistan) and finally KUTAPI and RKUTAPI by including Khazakstan and Russia.

POWER

NTPC unit in A.P. facing acute shortage of coal

June 11, 2005. The 2600 MW National Thermal Power Corporation (NTPC) unit at Ramagundam is facing coal shortage due to non-linkage of coal with the Singareni Collieries Company Limited (SCCL) for its newly-installed 500 MW seventh power plant. During the commissioning of the seventh 500 MW unit last year, the NTPC had signed an agreement with the South Eastern Coalfields (SEC), a subsidiary of Coal India Limited, for supply of about 3.5 million tonnes. But till date, not a single tonne of coal had arrived. Attributing the coal shortage to `mismanagement' by the NTPC, the Singareni company clarified that they were in no way concerned with the coal shortage, as they had not signed any agreement for supply of coal to the seventh unit. The SCCL had decided to supply about 10 million tonnes of coal to the NTPC during the financial year 2005-06. In the first quarter, as against the target of supplying 2.34 million tonnes, they had already supplied about 1.9 million tonnes and the remaining target would be completed by this month-end. Though it was decided to supply about 19,236 tonnes of coal to the NTPC every day, the SCCL was supplying 25,000 tonnes per day from its coalmines. The Central Government had fixed coal linkage with the SCCL for supply of about 7.5 million tonnes of coal per annum to the NTPC, Ramagundam. The SCCL could not supply coal to the NTPC, as it had already fixed coal linkage with other thermal power plants in the State.

Three power projects off the ground

June 10, 2005. The Public Investment Board of the government approved the setting up of three power projects entailing an investment of over Rs 5,000 crore (Rs 50 bn). Among the projects cleared, are two power stations in Jammu and Kashmir and a transmission project, costing around Rs 4,000 crore (Rs 40 bn) to evacuate power from Barh power station in Bihar. The 1,400-kilometre transmission line will feed power to states in eastern, western and northern parts of the country. The panel has also approved the 45 MW Nimoo Bazgo power project in Jammu and Kashmir at a cost of Rs 629.65 crore. National Hydroelectric Power Corporation (NHPC) will execute the project in 48 months from date of sanction. The 44 MW Chutak Hydro Electric Project in Jammu and Kashmir was also cleared by the panel. The project will cost Rs 631.72 crore (Rs 6.32 bn) and will be developed by NHPC.

Jindals plan captive power plant in Orissa

 June 9, 2005. Jindal Stainless Ltd (JSL) is set to sign a memorandum of understanding with the Orissa government tomorrow for setting up a 500 MW coal fired captive power plant in the complex at an estimated cost of Rs 2128 crore (Rs 21.28 bn). While the first unit of 125 MW of the CPP will be built by March 2007, the next three units of equal capacity are proposed to come up by March 2009. 

Orissa govt clears hydel projects

June 9, 2005. Amidst the possibility of mega thermal power projects being set up in Orissa, 20 mini and micro hydel proposals, having capacity to generate 250 MW of energy, have been cleared by the state government. The power generated by these projects, to be operated by private companies, would be purchased by the government in a buy-back arrangement. Several private companies had signed MoUs with the government for setting up these plants since 1994 but the same did not take off as no decision had been taken about the evacuation of the electricity generated with no buyer arranged. The government has agreed to purchase the entire electricity generated from these private power plants to be set up on different water bodies. But they would have to provide 12 per cent of the generated power to the government free of cost. Fresh MoUs would be signed with about 15 private companies for establishment of such hydro-electric projects. The companies who have evinced interest to set up mini and micro hydel plants in state included Orissa Power Consortium Ltd, Kakatiya Chemicals Pvt Ltd, Minakshi Power Ltd, Venus Energy Ltd, Sileru Power Generation Pvt Ltd and Ispat Alloys ltd.

Dadri project to get gas from RIL

June 8, 2005. The 3,740 MW power project in Dadri, Uttar Pradesh will receive gas supply from Reliance Industries Limited. The plant would be commissioned by 2008-09, he added. The project cost is around Rs 10,000 crore (Rs 100 bn). 

REL’s massive plant in Orissa

June 8, 2005. Reliance Energy Ltd (REL) is drawing up plans for a massive coalbased power plant in Orissa, at an estimated cost of Rs 48,000 crore (US$11 bn). This will, by far, be the world’s largest pithead coalbased power plant at a single location. The 12,000 MW plant will increase the entire country’s existing power generation by about 10 per cent, though there are other new power projects lined up. The investment would be about five times Reliance Energy’s US$2.3 bn market capitalisation. The project funding would be in a phased manner. Natural gas from Reliance Industries will be available as feedstock for the Dhirubhai Ambani Energy City (DAEC) project. As per current indications of gas availability, the DAEC project is likely to be commissioned in 2008-09. Reliance Energy was examining the feasibility of a 4,000 MW gas-based project in Maharashtra, where it is based. REL has just under 900 MW of generating capacity now, buying the rest of the 5,000 MW it sells from third parties. Its ambitious power generation plans come at a time when India needs private investment in power to sustain its growth.

SAIL to add more power 

June 8, 2005. Public sector steel major, Steel Authority of India Ltd (SAIL) is setting up two mega power plants of 500 MW each through joint venture companies at an investment of over Rs 4,500 crore (Rs 45 bn). Though largely meant for captive power requirements of the expanded steel facilities of SAIL, the proposed power facilities will for the first time also get into selling power to the grid at commercial rates. The move will not only help SAIL to put in place a long term strategy to reduce cost of operation of the steel plants through reduced power cost but also provide alternate revenue streams to the newly set up power joint venture firms of the steel major. At present SAIL gets about 500 MW of power for its requirements from its captive power units including joint venture units. It also purchases about 300 MW of power from the grid at over Rs 4 per unit. This cost would drop to less than Rs 2 per unit after commissioning of the new power plants. Besides, its own use, the new plants are also proposed to sell surplus power to the grid at commercial rates. Already, SAIL has received queries from Goa and Daman & Diu for supply of power from its proposed 500 MW plant at Bhilai. The Bokaro plant will also supply power to the city areas after meeting the captive requirements of the steel plant. The work on the Bhilai power project of 500 mw (2 units of 250 mw each) has already begun and is expected to be completed within two and half year period. The project is being implemented by Bhilai Electric Supply Company Ltd (a 50:50 joint venture between SAIL and NTPC).

Power supply in Andhra likely to improve 

June 14, 2005. The Transmission Corporation of Andhra Pradesh (APTransco) is currently resorting to load shedding due to loss of 1,300 MW of power generation on account of breakdown and overhauling of different power generating units and shutdown of a 500 MW unit of National Thermal Power Corporation at Talcher. There is no hydel generation at Nagarjunasagar reservoir due to maintenance works by irrigation authorities. No generation is possible even at Srisailam project as water level at the reservoir is below MDDL. On the other hand, power consumption has increased by 13 per cent now when compared to the corresponding period last year. APTransco is expecting that the situation will improve when the 500 MW unit at Simhadri Thermal Power Station and 210 mw unit of Rayalaseema Thermal Power Project, which are currently not in operation, are expected to be back in service. Besides, the Central Electricity Authority (CEA) has approved the proposal sent by the Andhra and Orissa states for depletion of water storage at Balimela reservoir to below the minimum draw down level (MDDL) of 1,440 feet so as to facilitate power generation at Upper Sileru project to full capacity of 200 MW.

NTPC vies for parallel supply licence in Korba

June 13, 2005. The National Thermal Power Corporation is vying for a parallel distribution licence for supplying power to retail consumers in Korba, Chhattisgarh. The State-owned generation utility is in the process of getting clearances from the Centre for the Korba venture to kickstart its foray into the electricity distribution business. The utility, which floated a wholly-owned subsidiary for power distribution, is also planning to apply for parallel distribution licences in other areas where it has its power stations, besides Korba. NTPC has a 2,100-MW thermal power plant in Korba. By applying for a parallel distribution licence, NTPC plans to become a second electricity distribution utility in Korba, alongside the Chhattisgarh State Electricity Board, which is now providing power. If NTPC bags a licence, retail consumers in Korba would have the choice of getting their power from either Chhattisgarh State Electricity Board or from NTPC's subsidiary. The Electricity Act 2003 allows utilities to apply for multiple distribution licences in various distribution circles, thereby ensuring consumers a choice of electricity service providers. Also, NTPC is in the process of applying for the distribution circles in Gujarat and Mangalore, Karnataka. The Uttar Pradesh and Gujarat governments had called for bids from utilities interested in taking over distribution of power.

Orissa breaks up power system

June 11, 2005. The transmission and distribution activity of the Orissa government-owned utility Gridco Corporation of Orissa (Gridco) was bifurcated and the transmission business vested with a new company Orissa Power Transmission Corporation (OPTCL). The move satisfied statutory requirements under the Electricity Act 2003 of the Centre on separation of transmission from trading and bulk supply. Gridco will continue to purchase power from generating utilities for sale to distribution companies by paying wheeling charges to OPTCL, responsible for transmission and grid management.

HT consumers can draw power directly

June 11, 2005. Karnataka has joined eight other States that allow high-tension power consumers who require 15 MW to draw power directly from supply companies or power traders of their choice. Karnataka Power Transmission Corporation Ltd. (KPTCL) said that there are 10 high-tension (HT) power consumers in the State. The system of allowing them to draw power directly from suppliers will be continued on an experimental basis for some time. After a year, the system will be extended to consumers with a requirement of 10 MW and above. KPTCL will function as a facility provider under the provisions of "open access for wheeling of power," as per the provisions of the Electricity Act of 2003. This is aimed at introducing competition and paving the way for improvement in services.

Power trading to be transferred to discoms

June 8, 2005. The Andhra Pradesh government today announced two major decisions in power sector. In compliance with the provisions of the Central Electricity Act, the government has decided to transfer power trading activity to the four distribution companies (discoms) from APTransco. Trading operations would be handled henceforth by a committee formed with the four discoms. Also the state government, through its generation company AP Genco, will set up a 1,600 MW Super Critical Thermal Power Station (2x800 MW) at the port town of Krishnapatnam in Nellore district. The new mega thermal power project would be completed by 2009. Genco will identify the firms for the construction of the project through international competitive bidding route. The consumer tariff will remain uniform across the state even after the decentralisation of trading activity. After this Transco will be reduced to just a wiring company. 

150,000 power connections for farm sector

June 13, 2005. The Andhra Pradesh government sanctioned 150,000 new agricultural power connections as part of its efforts to provide additional irrigation facilities for dryland agriculture. As per details 50,000 new connections will be given during the current fiscal under free power category while 100,000 connections will be provided under Tatkal scheme in the paying category. The sanction covers all distribution companies and provides 15 per cent quota to scheduled castes and six per cent quota to scheduled tribes. District-wise sanction of new connections has also been worked out on the basis of the total agricultural services existing in the state. Incidentally, Andhra Pradesh has the largest number of agricultural pumpsets when compared to any other state in the country. The state has 23.78 lakh (2.38 mn) pumpsets surpassing Maharashtra’s 22 lakh (2.2 mn) agricultural power connections. By providing 150,000 additional power connections, the state will have over 25 lakh (2.5 mn) agricultural pumpsets by the end of the current fiscal. 

NTPC plans to produce 50 mt coal by 2010

June 12, 2005. With coal shortage wrecking domestic power production, National Thermal Power Corporation is working on an ambitious plan to produce 50 million tonnes of coal over the next five years, which can wipe out the country's production deficit. The company is also working on an `integrated project development strategy' wherein it will focus on developing pithead stations close to the mines allocated to it, thereby bringing down the cost of power generated substantially. NTPC forayed into coal mining in 2002-03 and applied for 16 coal mining blocks. The utility has, however, been able to bag only one coal block so far, with access to a number of these blocks still awaiting mandatory clearance. The company has projected an output of 10 million tonnes by 2007 from the Pakri Burwadih coal block - the only one awarded to it so far. NTPC has also factored in a production of 30 million tonnes of coal from the blocks it is eyeing in Orissa and Chhattisgarh. The company is scouting for a captive coal mining block at Brahmani district in West Bengal for the new 500 MW unit coming up in West Bengal. Over 80 per cent of NTPC's stations are coal-fired, while the remaining use natural gas as fuel. NTPC, which is on a power expansion drive, will add 2,000 MW of thermal capacity by the end of 2006.

CIL to augment production by 20 mt 

June 11, 2005. Coal India Ltd (CIL) has recast its production plan in order to meet the country's non-coking coal requirement by 2010-11. Under the revised plan, CIL will augment production to a minimum of 20 million tonnes (mt) every year beginning from 2005-06. This means production will increase to 363 mt by 2006-07 from 323 mt in 2004-05. The production increase schedule is expected to continue at least till 2011-12. Almost the entire additional production will come from opencast mines. In this situation, the coal companies under CIL hardly have any option but to conduct aggressive opencast mining. One reason behind the plan to raise output is the production shortfall arising from the failure to develop virgin coal blocks allotted to various SEBs and private companies for captive mining purposes. Over 60 virgin blocks with combined reserves of about 5.5 billion tonnes (bt) of non-coking coal have so far been allotted during the last 10 years. The demand-supply mismatch may not exist beyond the terminal year of the Eleventh Plan (2011-12) following CIL's plan to raise production. The long distance, bulk non-coking coal consumers should not have faced any shortage as there was abundant mining capacity available at the giant coalfields such Gevra and Korba in South Eastern Coalfields Ltd (SECL) and at Ib Valley coalfields in Mahanadi Coalfields Ltd. The additional production would come mostly from new as well as expansion projects, while a part of the additional output would be generated from existing mines. A total 102 coal projects have been identified for implementation in the Tenth Plan. As per the Government's investment norms, 28 projects have been sent to the Union Government for its approval since capital investment in these projects is over Rs 100 crore (Rs one bn). The Government has so far approved four opencast projects, namely, Basundhara, Bhubaneswari, Kaniha and Kulda. Meanwhile, the CIL board has approved a total 18 projects and is in the process of clearing another 13 projects. As the capital investment in each of the project under CIL's consideration is below Rs 100 crore (Rs one bn), no Government approval is required. Similarly, CIL subsidiaries have approved about 40 projects.

Power firms to import coal

June 10, 2005. In a bid to tide over the acute coal shortage, power companies like the National Thermal Power Corporation, Reliance Energy and several State electricity boards will import about 13.25 million tonnes of coal in the current fiscal. This is a sharp contrast from last year when the country relied completely on domestic production to meet requirements of the power sector. Coal shortage had already forced the NTPC to shut down one 500 MW unit at the Talcher plant in Orissa. In addition, six thermal power stations had less than four days stocks while 16 other plants had stocks of less than a week. Power generation had also been affected at several plants of NTPC. MMTC had been asked by the NTPC to import 3.98 million tonnes of coal. The Tamil Nadu Electricity Board will also be importing 1.56 million tonnes coal. Other agencies importing coal will be the Maharashtra State Electricity Board, Reliance Energy and the Punjab SEB. Currently the country has 9.6 million tonnes of coal inventories though it should have 18 million tonnes of coal stocks.

Plan power to fall 10 per cent short

June 10, 2005. The power ministry has estimated that capacity addition in the Tenth Plan will be 37,000 MW against the targeted 41,110 MW. The shortfall of 10 per cent will, however, be made up by absorbing an additional 5000 MW in the national grid from captive capacity. In the next Plan period, capacity addition of 60,896 MW will be required in order to meet peak demand and energy requirements in the country. Of the total, thermal power will need to generate 33,536 MW and hydro power will have to contribute 22,420 MW. Nuclear power accounts for 4,940 MW in the period between 2007-12. The central electricity authority (CEA) has already identified thermal projects of 71285 MW and hydro projects of 2902.5 MW, to be completed during the next Plan. Each state has been asked to firm up the Eleventh Plan capacity addition programme and send a report to the power ministry within two months. Simultaneously, letters of award and commissioning schedules are to be firmed up for public and private sector projects, which are to be developed during the next Plan period. Simultaneously, the ministry is also holding regular review meetings with equipment manufacturers to ensure that equipment shortage does not slow down the capacity-addition programme. Bhel, a major equipment supplier, has planned a capacity-augmentation programme for the next Plan period. It aims to increase its annual manufacturing capacity from 6,000 MW to 10,000 MW by end 2007. The total installed generating capacity in the sector is around 1,18,419 MW. Thermal power accounts for 69 per cent of this. 

RIL commits gas for Reliance Energy

June 9, 2005. Reliance Industries Ltd (RIL) has agreed to supply natural gas to the proposed 3,740 MW power project of Reliance Energy Generation Ltd (REGL) at Dadri. The project was likely to be commissioned by financial year 2008-09. The company had a comprehensive plan to explore various opportunities in coal, gas, hydro and wind power generation projects with a total estimated investment of Rs 68,750 crore (Rs 687.5 bn). The Rs 11,000 crore (Rs 110 bn) power project proposed at the Dhirubhai Ambani Energy City (DAEC) near Dadri is expected to be the world’s largest gas based power generation plant in single location. 

The company had already initiated steps to set up a 12,000 MW coal-based power project in Orissa at a cost of Rs 48,000 crore (Rs 480 bn). In addition, the company has also been qualified in the internationalcompetitive bidding process for implementing the 1,000 MW Anpara “C” power project in Uttar Pradesh. In hydro power sector, REL has recently bagged the 280- MW Urthing Sobla hydro project in Uttaranchal. The investment for this project was estimated to be Rs 1,500 crore (Rs 15 bn). The company is also pursuing now the implementation of up to 500-MW of wind-based power projects in phases spread across various states. The company was keenly following the developments in nuclear power generation and would pursue growth opportunities at an appropriate stage.  In the power transmission sector, REL has already participated in the international bidding process of the Power Grid corporation of India Ltd., for selection of a joint venture partner for setting up of transmission lines for Parbati and Koldam hydro electric projects in Himachal Pradesh on a BOOT basis. In this project, the company anticipates an investment of Rs 750 crore (Rs 7.5 bn). For transmission business, the company has also applied to the Central Electricity Regulatory commission (CERC) for obtaining transmission licenses to undertake a total of seven schemes and packages for strengthening of transmission system in the western region. It has planned an investment of about Rs 5,000 crore (Rs 50 bn) for undertaking transmission projects in this region. In addition to this, the company is also exploring a comprehensive transmission network covering northern India for evacuation of power from its 3,740 MW plant in UP at an estimated outlay of Rs 2,500 crore (Rs 25 bn). 

Tata to help Maharashtra in power crisis

June 9, 2005. Tata group offered Maharashtra help to tide over the acute power crisis. Tata group would provide all possible help, including technical support, to the state government in an effort that the industries in state does not close down and the impact on the investment in the state is negative. The state government would also be provided help for getting power from the state and outside the state the group said. The joint efforts of state government and industries would definitely help in tackling the power shortage in the state.

Neyveli to go solo

June 9, 2005. Neyveli Lignite Corporation Ltd (NLC) is to single handedly go ahead with the Jayamkondam integrated mining-cum-power project that envisages a total investment outlay of Rs 11,000 crore (Rs 110 bn) to set up a 2,000 MW power plant and an accompanying lignite mine. The project will have two phases. In Phase I there will be a 1,000 MW power plant with a 8 to 9 million tonne lignite mine at an investment of Rs 6,000 crore. The capacity will be enhanced to 2,000 MW in the Phase-II with an investment outlay of Rs 5,000 crore (Rs 50 bn). The Tamil Nadu government has given its consent for NLC to take up the Jayamkondam project. The Jayakondam project will be jointly taken up by NLC and the Tamil Nadu Electricity Board (TNEB). Almost 70 per cent of power generated by the Jayamkondam project will be supplied to Tamil Nadu while the remaining will be distributed to other three southern states. Also the Tuticorin project will have only a power plant of 1,000 MW capacity with a outlay of Rs 4,000 crore (Rs 40 bn). There is an option to import coal for this project. Both these projects are expected to get the central government’s sanction in a year’s time. NLC’s lignite mining capacity at Barsingnar mine and power projects in Rajasthan will be increased from 24 million tonne at present to 30.6 million tonne and power generating capacity from 2,490 MW to 3,140 MW by 2009- 2010. NLC was able to realise the current bills for supply of electricity almost 100 per cent during the year. The power dues was Rs 320.12 crore (Rs 3.2 bn) which is equivalent to 48 days of sales as compared to the outstanding dues of Rs 570.59 crore (Rs 5.71 bn) equivalent to 79 days of sales as on March 31, 2005. 

NLC to adopt new technology to check thermal power emissions

June 8, 2005. The Neyveli Lignite Corporation has taken appropriate steps to check emission from the thermal power stations in conformity with pollution control norms. It will also adopt a new technology to cut pollution in the proposed expansion projects. In line with government guidelines the utilisation of fly ash would be 100 per cent in another nine years; NLC was taking appropriate measures to ensure this.

India Inc pays highest power tariffs after Japan

June 7, 2005. Indian industry pays much higher for the power it consumes in comparison with even developed nations such as the US, Germany and the UK, with just their Japanese counterparts paying more. On the flip side, Indian households are the most pampered electricity consumers in the world, paying the lowest tariffs for the power they consume, as per the statistics available for 30 countries.

The extent to which cross-subsidies are rooted in the domestic tariff structure is evident from the fact that while Indian domestic tariffs are less than half of what is paid by industry, not even one of the other 29 countries charge industry more than domestic consumers. With the Centre bending backwards to accommodate pressure from the Left parties to do away with the provision in the Electricity Act 2003 mandating State Electricity Regulatory Commissions to phase out cross subsidies, the skewed tariff structure in the domestic power sector is likely to continue in the foreseeable future.

OIL & GAS

Jordan oil business relationship with Accel energy group

June 13, 2005. Accel Energy Group is seeking the utilization of its retort technology from the country of Jordan. The technology, owned by AGYG, provides a cost-effective method of extracting crude oil from shale rock. With the demand for oil continuing to increase worldwide, Jordan, who unlike neighboring countries has no oil reserves below ground, is seeking methods to profit from the oil contained in the large resource of shale rock found in the country. Jordan has approached Accel Energy Group to discuss the extraction of crude oil from shale rock. Accel Energy Group plans to visit Jordan to negotiate a long-term contract that would involve construction of the plant, technology transfer, operations and per-barrel royalty rights.

Significant gas discovery in Pakistan

June 13, 2005. The American Energy Group, Ltd. the Hycarbex-American Energy, Inc. Haseeb No. 1 well commenced on March 25, 2005, on the Republic of Pakistan Yasin Block (2768-7) approximately 9km (5.6 miles) from the City of Shikapur in the Sindh Province, has resulted in a significant gas discovery based upon a number of preliminary tests and evaluations, including electric logs, geologic and drilling data which have been reviewed by the Pakistan Government. The American Energy Group, Ltd. owns an 18% gross royalty in the Haseeb No. 1 well. The working interest is co-owned by Hycarbex (85%), Techno Petroleum (Pvt) Limited (10%) and Government Holdings (Pvt) Limited (5%). The well was drilled to a total depth of 1507 meters (4,944 feet). The drill stem test conducted over a short duration on a one-half inch choke indicated a production rate from the Sui Main Limestone equivalent to approximately 7.3MM cubic feet of 805 BTU gas per day.

Indonesia offers 27 areas for oil exploration 

June 10, 2005. Indonesia, Asia Pacific's sole Opec member struggling to boost crude output, offered 27 new exploration areas and sweetened the terms for foreign oil firms to find oil and gas in difficult fields. Indonesia is giving higher splits in some areas based on geological factors. Indonesia expect those areas will become attractive to investors for exploration. The government offered 25% to 35% production splits for investors in 20 areas, including in offshore Natuna and the Makassar Strait. Indonesia's standard oil production sharing contract is 85:15 in favour of the government and 70:30 for gas. Foreign investors have cited the small production split allotted to them as a major hurdle for not investing in the country's upstream sector. Indonesia was not likely to meet its budget target of crude oil and condensate production for 2005.

KSA has more oil than needed

June 10, 2005. Saudi Arabia has plenty of oil more than the world is likely to need -along with an increasing ability to refine crude oil into gasoline and other products before selling it overseas. The world is more likely to run out of uses for oil than Saudi Arabia is going to run out of oil. Saudi Arabia has proven reserves of 261 bn barrels and with the arrival of newer technology could extract an additional 100 bn to 200 bn barrels. Saudi Arabia now pumps 9.5 mn barrels of oil daily, with the capacity to produce 11 mn barrels a day. The country has pledged to increase daily production to 12.5 mn barrels by 2009, last month the level of 12.5 mn to 15 mn barrels daily could be sustained for up to 50 years. High oil prices benefit the Saudi economy in the short run. Nation wants a stable price that won't hurt consumers so much that they reduce their energy demands. The problem for both the Saudis and the United States is what happens after the oil is pumped.

Norway's Statoil aims to double gas output by 2015

June 8, 2005. Norwegian energy group Statoil aims to double its annual natural gas output to 50 bn cubic metres by 2015 it was on track to meet production and financial targets for 2007. Norway's biggest oil and gas producer also hiked its long-term oil-price assumption which guides new investment to $25-30 per barrel from $22, a move that analysts cheered as it would enable Statoil to compete more aggressively for assets. That would mean doubling the present level, and correspond to average annual growth of 8 percent in 2004 to 2015.

Energy groups off Norway, the world's third-largest oil exporter, are increasingly shifting to gas as big oil finds become scarce and output from mature oilfields falls. Norway is Western Europe's biggest gas producer, with sales this year estimated at 80 bn standard cubic metres. Statoil has earlier said its gas volumes would overtake oil around 2010, and about 60 percent of the company's current reserves are gas. Statoil said it would focus on liquefied natural gas (LNG), develop new fields and search for more gas both off Norway and elsewhere. It was also planning a second phase for its Snoehvit LNG field in Arctic Norway, due on stream in late 2006.

BP sees Baku-Ceyhan pumping 500,000 bpd in 2006

June 8, 2005. A giant Azeri-Turkish oil pipeline will start pumping 200,000-300,000 barrels of oil per day to the Mediterranean market later in 2005 or early next year, boosting volumes to 500,000 bpd over 2006. BP, which leads both the pipeline group and a consortium for three Azeri oilfields, said the projects were vital to cover growing global oil demand and help Caspian Sea crude bypass crowded export routes through the Turkish straits. The project will cover 1.2 percent of global demand. These supplies will be independent from the Middle East and Russia and they will represent 25 percent of incremental oil demand over several years.

BP tanks up for gas station expansion

June 13, 2005. BP is set to pump millions of dollars into its gas station empire. The leading foreign oil company in Poland, BP, has revealed plans to invest around $70 (zł.231) million to expand its network of gas stations over the next four years. The oil giant aims to increase its current total of 293 stations to nearly 400, largely through franchising.  Roughly 70 percent of them will be opened in the franchising system, while the remainder will be our own gas stations.  The top Polish refiner and retailer, PKN Orlen, recently announced plans to restructure its retail network in the face of competition from firms including BP. The British concern is aiming for a quick start off the line and hopes to have opened a further 15 new stations by the end of the year in a bid to gain further ground in the sector. Currently BP's total value of investments in Poland amounts to over $800 (zł.2,638) million. The company's Polish arm is aiming to boost fuel sales by four percent this year after achieving consolidated 2004 sales of $1.71 (zł.5.7) billion.

BP says Saudi cracker to produce 1.2 mln tonnes/yr

June 8, 2005. BP Plc. an ethylene cracker that its Innovene petrochemicals unit plans to build in Saudi Arabia will have a capacity of around 1.2 mn tonnes of ethylene a year. This would be used to produce around 800,000 tonnes of polyethylene and around 500,000 tonnes of other olefins each year. Innovene planned to build the $2 bn cracker in conjunction with Saudi-owned Delta International, and that commissioning of the project was expected in late 2008.

N. Australia weighs a $250 mn condensate refinery

June 8, 2005. Australia's Northern Territory government is in talks with potential investors to build a refinery costing up to a$250 mn ($192 mn) using condensate from the Timor Sea. The project could cost between a$200 mn and a$250 mn. Condensate is a very light form of crude oil recovered from natural gas reserves. It is usually blended with crude for processing at oil refineries but can be used on its own in special plants that produce primarily naphtha and light products. The project is due to start producing liquefied natural gas (LNG) next year from a processing plant at Wickham Point near the Northern Territory capital of Darwin.

China LNG import capacity at 20 mn T by 2010

June 7, 2005. China's booming economy and surging power demand will see liquefied natural gas (LNG) import capacity grow from zero to 20 mn tonnes in the next five years. A consortia of buyers from China, the world's second-largest energy consumer after the United States, is due to import the country's first LNG shipments next year from Australia's largest resource development, the A$14 bn North West Shelf.

By 2010, China's gas consumption will more than treble to 3.9 trillion cubic feet (tcf) from 1.2 tcf in 2003, outstripping production growth, which is projected to rise to 2.6 tcf from 1.1 tcf over the same period. By 2010, LNG import capacity is expected to reach around 20 mn tonnes and by 2020, between 50 to 60 mn tonnes. The government is aiming to increase the share of natural gas in its energy mix to 7 percent by 2010.

Iran pipeline may be extended to China

June 13, 2005. Iran has agreed to explore possibilities of extending the 2600-km Iran-Pakistan-India pipeline to China, according to Petroleum Minister Mani Shankar Aiyar, who headed the Indian delegation at the ministerial level talks with Iran on natural gas imports. During his discussions with Iranian Oil Minister Bijan Zanganeh, Aiyar also asked for extension of the quantity of the liquefied natural gas Iran will export to India from 2009-10 to 7.5 mn tons from the 5 mn tones already agreed. Iran has refused to give concession on price for an additional 2.5 mn tonnes of the LNG New Delhi wants to buy over and above the 5 mn tonnes per annum of LNG already agreed. On the contrary, the Iranian side has proposed a hike in price. India also wants the LNG composition to be similar to Qatar's as far as possible. Since Qatar's LNG contains nearly 9.5% C2/C3/C4 components, Iran should at least commit 5% C2 as they are likely to extract most of the C3 and C4.

Iran-India-Pakistan gas pipeline decision in two weeks

June 13, 2005. A decision on the multi-bn-dollar pipeline between Iran and India that will run across Pakistan will be made in two weeks. Iran was willing to sell gas to India and Pakistan and that talks were progressing.  The 2,600-kilometre (1,600-mile) overland gas pipeline project, with an estimated cost of about 4.5 bn dollars, has been strongly opposed by the United States because of its concerns about Tehran's nuclear programme.  The two countries have also finalised an agreement for Iran to deliver 5.0 mn tonnes of gas to India over 25 years, and are in talks for the supply of another 2.5 mn tones.

Baghdad plans cut in crude exports

June 12, 2005. Iraq plans to cut its oil exports by 15 percent in the second half as terrorism and lack of investment take their toll on infrastructure. The new export figures imply an export volume of 1.45m barrels a day or 250,000 bpd below the contracts offered in the first half. The forecast remains above the one-year low of 1.3m bpd after field maintenance problems last month. The reduction is the second this year and follows six months of delayed cargoes and cancelled contracts as Iraq has struggled to keep its contractual agreements in the face of sabotaged oil pipelines in the north and deteriorating oil field productivity in the south.

PetroChina buys overseas assets for $2.5 bn

June 10, 2005.China's top energy producer, PetroChina Co. will buy overseas oil and gas fields from its state-owned parent for $2.5 bn, offsetting stagnant domestic output and laying the groundwork for more acquisitions abroad. PetroChina will take a 50 percent stake in a new company that owns a large share of parent CNPC's overseas assets, giving the company oil fields in 10 new countries, with the brunt in Kazakhstan, Peru and Venezuela.

Indonesia seeks investment to boost oil output

June 9, 2005. Indonesia, Asia Pacific’s sole OPEC member struggling to boost crude output, offered 27 new exploration areas and sweetened the terms for foreign oil firms to find oil and gas in difficult fields. The government offered 25 to 35 percent production splits for investors in 20 areas, including in offshore Natuna and the Makassar Strait. Indonesia’s standard oil production sharing contract is 85:15 in favour of the government and 70:30 for gas. Foreign investors have cited the small production split alloted to them as a major hurdle for not investing in the country’s upstream sector. Indonesia was not likely to meet its budget target of crude oil and condensate production for 2005.

Russian energy exports to EU may rise

June 8, 2005. Energy exports to the European Union are expected to increase further in coming years. Russian news saying that diversifying export routes and the development of new oil and gas fields would help fuel the increase. Russia is the EU's fifth-largest trade partner, with exports to the 25-country region amounting to $91 bn last year. Natural gas monopoly Gazprom provides a quarter of Europe's gas, while 85 percent of Russia's 2004 oil exports went to Europe. Gazprom and Spanish-Argentine oil giant Repsol YPF SA were in discussions to increase cooperation as Repsol tries to step up its production, sale and transport of liquefied natural gas.

UAE, China ink MoU to boost energy, oil ties

June 14, 2005. The UAE and China signed a memorandum of understanding, aimed at bolstering bilateral relations in the energy and oil sector. The UAE is evaluating export opportunities to this huge market which will turn into the world’s largest energy consumer market within the next few years. UAE is ready to meet China’s demand for oil and gas and further expressed the hope that Chinese companies would acquire a fair share in the mega oil and energy projects in the UAE. The Middle East market is small for China when compared to the volume of consumption in the region. Nevertheless, the UAE stands a better opportunity of becoming an important trade and economic partner.

Petronas still involved in Iran gas project

June 13, 2005. Malaysia's national oil company Petronas has not pulled out of a $2 billion (euro1.54 billion) joint-venture in Iran to develop the world's largest offshore gas field but is still in negotiations to seek an agreement on commercial terms. The company was evaluating the financial viability of the South Pars liquefied natural gas, or LNG, project, in which it holds a 20 percent stake. Petronas has withdrawn from the project amid disagreement over commercial terms. The other stakeholders are Total SA of France which owns 30 percent and state-owned National Iranian Gas Export Company which holds the remaining 50 percent. Iran sits on the world's second largest proven gas reserves after Russia. South Pars, which is believed to be the world's largest gas field, is shared by Iran and Qatar. It is estimated to hold equal to 7 percent of the world's total gas, and 38 percent of Iran's reserves.

Iran pipeline cannot be abandoned, US

June 12, 2005. Pakistan is believed to have informed the United States that it cannot abandon the Iranian gas pipeline project despite a strong US opposition to the scheme. Ms Rice, who has publicly opposed the project, reiterated Washington’s position that the proposed pipeline, which will be bringing Iranian gas to India through Pakistan, is against US laws. The US Iran and Libya Sanctions Act of 1996, known as ILSA, forbids more than $20 million of investment in Iranian oil and gas projects. The violator can be deprived of US economic assistance and may also face sanctions. Ms Rice is believed to have argued that even if the US administration gave up its opposition to the pipeline, there were powerful groups in Congress, media and academia that would continue to oppose the project and it will ultimately adversely affect Washington’s relations with Islamabad.

Gazprom and Iran to cooperate in gas projects

June 12, 2005. Gazprom and Iran discussed prospects of bilateral cooperation in the gas sector and agreed on enhancing cooperation in certain projects, like exploration work and the creation of underground gas storages in Iran, design of a general scheme for gas supplies on the Iranian territory, the development of gas transportation system in the country and Gazprom's participation in pipeline construction in Iran. They signed a protocol, which stipulates establishment of working groups in charge of the above-mentioned projects. The National Iranian Oil Company (NIOC) is the only gas producing company in Iran. It supplies gas to NIGC. NIGC has 8 refinery and gas dewatering plants with overall capacity more than 380m cubic meters per day. Iran's proved reserves of natural gas are estimated at 27 trillion cubic meters. Gas production shows annual growth of 10 percent. It exceeded 140b cubic meters last year. Almost all gas is sold on the domestic market.

Australia's NW Shelf approves LNG expansion

June 10, 2005. Australia's Woodside Petroleum Ltd. said partners in the offshore North West Shelf LNG project would spend a$2 bn ($1.5 bn) to raise output of the easily transportable energy to meet growing world demand. The expansion will take three years to complete and add a fifth leg to the project in Western Australia, boosting output by 4.2 mn tonnes to 15.9 mn tonnes.

Pak to review diesel imports ban

June 8, 2005. Pakistan will review a ban on import of diesel and petrochemicals from India when it next prepares the draft of the import-export policy, India’s Petroleum Minister Mani Shankar Aiyar. Aiyar could not take up the matter with Pakistan’s commerce minister, who was not in the city, and nor was he able to say when Pakistan would review its import-export policy next. Indian Oil Corporation (IOC) has offered to export 325,000 tonnes of diesel through the Karachi port and the Wagah border to Lahore and Jhelum, respectively, during October 2005 to March 2006. The delay on the Pakistani side to lift the ban on diesel and “LAB” imports from India had been a boon as by the time the policy was reviewed, IOC’s Panipat refinery expansion would be completed, increasing availability of exportable fuel. Besides, the Panipat petrochemical complex will be up and running by October 2005.

POWER

CNNC boosts nuclear power output

June 14, 2005. China National Nuclear Corporation, the nation's largest reactor builder, intends to use its own technology to build two 650-megawatt reactors and two 1,000 MW reactors at its Qinshan plant, which will more than double its generation capacity. Upon completion of both projects, the installed capacity of the Qinshan nuclear power plant will be set to rise to 6,200 MW from the current 2,900 MW generated by five running reactors. Total investment for the planned expansion projects is expected to reach US$4.33 billion, based on construction costs provided by CNNC. For the two 650-MW reactors, it will cost US$1,330 for each kilowatt of added capacity. The 1,000 MW reactors are US$30 less for each kilowatt to build because of the technology that the two gigawatt reactors will use.

More nuclear plants in Pakistan

June 11, 2005. Pakistan Atomic Energy Commission (PAEC) said Pakistan would build 10 to 12 more nuclear power plants to achieve future energy needs of 8,800 MW by 2025. New power plants would be constructed along the sea coast and river Indus for which necessary manpower is being trained to build and run these units indigenously.

Britain is becoming over-reliant on imported gas

June 14, 2005. Government policy is causing Britain to become dangerously over-reliant on imported gas, the consultancy group Ernst & Young claimed. It says clean coal and nuclear generation is being ignored in favour of gas and wind power, and is calling for an urgent debate on the mix of fuels used to generate the UK's electricity. The UK is in danger of creating a fuel mix that is less diverse, less secure and hampered by price volatility, which could directly impact the UK's competitiveness. UK policy around diversity of fuels and technology is poor. Government has taken an 'all eggs in one basket' approach to energy policy, favouring renewables and in doing so discriminating against alternatives, particularly clean coal and nuclear.

System loss in power sector - Bangladesh

June 13, 2005. The government loses Tk 65 crore (TK 650 mn) annually from just one per cent system loss in the power sector. If the system loss could be pegged at a tolerable level, the government would earn additional revenue of about Tk 650 crore (Tk 65bn). The government had taken various steps to overcome the system loss in the power sector. The steps include ensuring meter for consumers, computerisation of billing system, introducing pre-paid meter in some sectors, and cutting-off power supply to illegal and defaulted consumers by mobile court. Two power generation units have been set up following an agreement with a US company. The two units will generate 810MW electricity Haripur 360 MW and Meghnaghat Phase-One 450MW.

UAE power sector to attract $10 bn

June 10, 2005. Driven by a fast growing demand that surpasses even the most optimistic projections, power generation in the UAE is poised for a phase of exponential growth in the next five years. The boom, which has been evident across the property and varied service sectors in the Emirates over the past couple of years, has made it necessary to have the demand projections revised drastically. The UAE, already in the forefront claiming one of the fastest power demand growth rates at 10 per cent as against the global average of three per cent, is facing a major spurt in consumption in the backdrop of a drastic population growth and a spectacular building boom which is putting pressure on the country's installed capacity of just over 10,000MW.

UAE's power sector would require more than $10 bn in new investments over five to seven years as consumption surge will sustain at 10 to 12 per cent growth. The country's installed power generation capacity, which has been growing at an annual 24 per cent over the past 30 years, is poised to reach 15,000 MW to 17,000 MW within the next five years to cope with the demand surge triggered by the current all round developments. In the recently announced budget, the UAE Federal Electricity and Water Authority's power generation and distribution programme received the largest budget of any department, at Dh 1.68 bn, underscoring the priority attached to this sector.

The latest estimate is that the Middle East requires an investment of more than $1 trillion over the next 20 years, mainly in utility sector, with a strong focus on power generation, distribution and lighting. Some 33 per cent of works for the UAE National Power Grid project, which will include Abu Dhabi, Dubai, Sharjah and Fujairah power grids, has been already completed. Bids for the Dh4.6 bn Gulf Power Grid will close by mid-June and the contract awards for the first phase are expected to be announced by September. The grid will, by 2008, connect Bahrain, Kuwait, Qatar and Saudi Arabia, with the UAE and Oman being added later. The massive project involves cabling, building substations and networking all the six countries. According to a long-term perspective, the Gulf region is expected to invest more than $100 bn to meet the growing power demand that is expected to rise to 116,000MW by 2020. But in the short term, total investments in the AGCC power sector will be some $46.4 bn for covering expansion of existing power plants and setting up of new projects to add around 37,000MW to their current capacity by 2010. While Saudi Arabia will require an investment of $20 bn, investments in Kuwait are estimated at $3.6 bn, $3 bn in Qatar, and $1 bn in Bahrain, and $800 mn in Oman.

Wind power capacity to save tax in Gujarat

June 9, 2005. Between October 2002 and March 2005, as many as 59 corporates have set up wind-driven turbine generators (WTGs) in Gujarat to produce power. WTGs in Gujarat have an installed capacity of 236 MW. These corporates, which have forayed into power generation, include a variety of firms. They range from pharmaceutical companies, clock makers, potato wafer makers to denim manufacturers, chemical units and export houses. While most corporates are said to have gone in for WTGs to save tax (some have set up WTGs for captive use), their move has come as a boon to the state electricity board, Gujarat Urja Vikas Nigam Limited. That is because Gujarat is facing a power shortage. The question is, why these companies are setting up WTGs. There are two reasons for this. First, income tax that a company pays on depreciation is higher when non-conventional sources of energy are employed for power generation. Secondly, there is a ten-year tax holiday on income tax for incomes from the sale of non-conventional energy. Explaining, industrialists say that in case textile machinery is purchased, and if there is a profit of Rs 100, a depreciation of 25 per cent is calculated. This means that a company pays income tax on 75 per cent of the profit. However, in the case of wind mills, there is an 80 per cent depreciation, which means that for a profit of Rs 100, a company needs to pay income tax on just Rs 20. An added advantage is the fact that if companies do not want to use power generated for captive purposes, the state electricity board will purchase it anyway. In the past two financial years, Gujarat has added about 51 MW of installed capacity of wind power generation to aggregate a total capacity of about 236 MW. 

Major biofuel projects around the world

June 8, 2005. In United States, North Dakota Biodiesel Inc. plans to build a $50 mn biodiesel manufacturing plant in Minot, North Dakota drawing on local canola crops as a source. The facility will be the largest biodiesel refinery in North America, able to produce 100,000 tonnes of premium biodiesel annually from more than 355,000 acres (144,000 hectares) of canola. Construction on the plant is expected to begin in August, with the first sale of biodiesel products likely in December 2006.

In Malaysia, leading oil palm planters IOI Corp and Kuok Oil & Grains are separately building two refineries in Rotterdam to process more than 1 mn tonnes of palm oil a year. Industry experts say the plants will deliver much-needed supply to Europe's biodiesel plants in future. In Brazil, State oil giant Petrobras has projects to increase ethanol exports to 9.4 bn litres in 2010 from 2 bn litres in 2005. Japan's Mitsui & Co. is to team up with Petrobras and Vale do Rio Doce to study how to expand Brazil's ethanol exports.  In Austria, Austrian starch, sugar and food processor Agrana will build a 105 mn-euro bioethanol plant with an annual capacity of 200,000 cubic metres. In Spain, Abengoa Bioenergy, Europe's top ethanol producer, is due to open a 200 mn-litre plant in northern Spain at the end of this year. It wants to start up another two in Europe in the next five years, and is most interested in Germany and Britain. It is also bidding for a project in France. The bioenergy unit of Abengoa produced 260 mn litres of ethanol in Spain last year and about 400 mn litres in the United States. In France, France's main biodiesel maker Diester Industrie, owned by oilseed producers, should be able to lift its output to around 1 mn tonnes a year in 2007-2008 under a new quota agreed by the government earlier this year. French maize producers and Abengoa, the top European ethanol producer and the fifth in the United States, hope to produce 100,000 tonnes of ethanol, or 1.26 mn hectolitres (mhl) at a plant to be built in southwestern France. Other French bioethanol projects include two joint sugar and wheat-based production plants, one proposed by France's top sugar producer Tereos and the other by Cristal Union, with a capacity of 200,000 tonnes each. In UK, a 100,000-tonne biodiesel plant, owned by British supermarket giant Tesco (TSCO.L: Quote, Profile, Research) and renewable fuel maker Greenergy, is expected to come onstream on England's east coast by next year, expanding the potential for green fuels. Greenergy hopes to sell up to 3 mn tonnes a year of biofuel. British Sugar's largest UK sugar factory has filed a planning application to build an ethanol plant with a production capacity of 50,000 to 60,000 tonnes in eastern England. Dutch independent refiner Petroplus planned to ramp up sales of its "Bio-plus" (5 percent biodiesel) fuel this year after securing up to 25,000 tonnes per year of biodiesel from Scottish start-up Argent Energy. The company produces 200,000 tonnes of biodiesel a year. In Saudi Arabia, U.K. biodiesel developer D1 Oils has started a joint-venture project to produce biofuel in Saudi Arabia for export to Europe.Saudi company Jazeera for Modern Technology will provide land to grow Jatropha, a non-edible plant producing oil for blending with diesel, while D1 will build a processing plant in Saudi Arabia to come onstream in the second half of 2006. The plant will be able to process 8 mn litres a year.

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