MonitorsPublished on Jan 30, 2007
Energy News Monitor I Volume III, Issue 32
What do falling crude prices mean for India’s Fiscal Deficit?




Proponents of petroleum taxes argue that the tax would significantly increase revenue thus reduce fiscal deficit and consequently lower interest rates and raise investment. Opponents of petroleum taxes counter that it would not reduce the fiscal deficit significantly when all of its economic effects are taken into account, increase inflation and impose financial hardship on low and middle-income families.  


India’s Fiscal deficit of Rs 1,40,955 crores in 2001-02, stood at 6.1 percent, which was the highest in recent years after which it has constantly fallen.  Historically, if we look at budget estimates, revenue receipts tend to be estimated higher than the actuals while tax receipts tend to fall short of expectations. 


However, India’s budget in 2003-04 defied the trend. The actual revenue collections exceeded not only the budget estimates but the revised estimates as well. As per the RBI, the significant improvement in public finances since 2002-03 is due to ‘policy efforts at fiscal consolidation as well as the upturn in economic activity’.  Going by the budget speech in February 2006, ‘path breaking’ developments on the fiscal front are due to the success of ‘enhanced revenue mobilization through reasonable rates, better compliance and widening of the tax base’. 


Contribution of the Petroleum Sector to Central Exchequer


Administered Price Mechanism (APM) for crude was ‘dismantled’ from April 2002.  This regime implied price control under a cost plus regime with a more or less stable burden of duties and taxes that were dependent more on trade volumes rather than fluctuations in market prices. The post APM period has been continuing with an ad-valorem structure for duties and taxes in tandem with a dramatic rise in international crude prices. 


Between 2003 and 2006 the ad-verolem duty on petrol reduced from 30 percent to 8 percent while the specific component was increased from Rs 7.50/litre to Rs 13.00/litre. For diesel, the ad-velorem component was reduced from 14 per cent to 8 percent and the specific component was increased from Rs 1.50/litre to Rs 3.25/litre. As crude prices soared, cess on crude production was first doubled to Rs 1800 in March 2002 and then raised to Rs 2500 per ton in 2006.  

It is noticeable that 52 percent of the price paid for petrol at the pump in Delhi actually consists of duties and taxes on which the state sales tax collects 15 percent while the remaining is accounted for by excise and customs. The excise duty on petrol rose from Rs 5.32 per litre in 2000-01 to Rs 15.11 in 2006-07: a rise of almost 300 percent.  For diesel the corresponding increase was from 2.55 to 5.19 (200 percent). The net result:


·    The contribution of the Petroleum Sector (as per PPAC estimates) to Central Revenues rose from Rs 46,603 crores in 2001 to Rs 87,649 crores in 2005-06.  The impact on state revenues was as great.


·    Had crude prices remained at 2002 levels, revenue collections by the Centre would have been at least Rs 20,000 to Rs 25,000 crores lower.


Ostensibly, the rise in duty rates should have been used to finance the increasing subsidy burden on kerosene and LPG due to the rise in crude prices.  However the subsidy was kept constant at Rs 2,930 crores whereas the balance was made up by either the oil companies or transferred to future budgets by way of bonds. 


Oil bonds for Rs 14,500 crores were issued in 2005-06 and Rs 25,300 crores for the current year. The projected shortfall for 2006-07 by way of under recoveries is Rs 67,000 crores. What is pertinent is that this is so in spite of Rs 12,500 crore secured by way of price discounts on crude and Rs 3,225 crores available from the sale of ONGC shares.


If crude prices fall again as they have been doing what would be the net impact on the revenues to the Centre? Would we still be able to conjure out of the hat, budgets with fiscal deficits below 4.5 percent? 


Obviously not. Falling crude prices would lead to lower excise collections, lower royalty and cess on indigenous production and ultimately translate to lower dividends. In all revenue collections may actually fall short by as much Rs 20,000 crores in a fiscal year. The average Indian basket price of crude for year 2005-06 was  $ 55 per barrel.  At a basket price of $ 55 per barrel, the contribution of the petroleum sector to the Central exchequer was approximately Rs 87,647 crore as per 2005-06 budget figures.   


If we take the average Indian basket price of crude for year 2005-06 at $ 55 per barrel as the base and if we increase the basket price of crude to $ 80 per barrel holding all other factors constant, the contribution to the Central exchequer increases to about Rs 1,30,412 crores. This would mean that the fiscal deficit would have been lower by Rs 42,765 crores (please refer to table at 2nd page), had the price of crude been $ 80 per barrel rather than $ 55 per barrel in 2005-06. If we reduce the basket price of crude to $ 22 per barrel holding all other factors constant, the contribution to the Central exchequer falls to Rs 34,024 crores.  The fiscal deficit would have been higher by Rs 53,623 crores (please refer to table at 2nd page), had the price of crude been $ 22 per barrel in 2005-06.


In the era of rising crude prices (as in the reference year 2005-06) the excise duty on petrol was ‘rationalised’ from a high ad-velorem rate of 23 percent to 8 percent while the fixed component was increased from Rs 7.50 per litre to Rs 13 per litre.  In the era of falling crude prices, a low ad-velorem component along with a high fixed component for excise would result in substantial reduction in revenue.  Note that the above projections overlook all other impact of change in crude prices so as to focus on the sensitivity of tax revenues on crude prices.


It is acknowledged that excise and other levies from the petroleum sector during a period of sustained high or low crude oil prices could be offset by reductions in income and direct tax revenue. The subsidy burden, whether revealed in the budget or not, would also increase or decrease proportionally. 


Inflationary effect of high oil prices may also add to any government expenditure indexed to inflation.  When these effects are taken into account, the contribution of the petroleum sector to the government exchequer would be very different from those projected above. At a more local level, the price of the petrol in Delhi has nearly doubled between 1999 and 2006 while the excise component has increased three times in the same period from a level of Rs 5.99 per litre.


As noted in the ORF Policy Brief on the Impact of High Oil Prices, dated September 2006, the anomaly of ad-valorem taxes may be corrected by making the duties specific and uniform across the country, as recommended by the Dr. Rangarajan committee.


Pricing of Petroleum Products: Impact on the Reform Process


In a paper on ‘Macroeconomic Policy Reforms in India’ for a joint ORF – World Bank publication on ‘Documenting Reforms’ in India, Dr Ashok Lahiri, Chief Economic Advisor, Ministry of Finance acknowledges that the ‘marksmanship in budget making had improved with the implementation of the FRBM Act.  His paper observes that the revenue deficit as a proportion of GDP was down by 1.8 percentage points in 2004-05 (Provisional) since 2002-03, which was in excess of the minimum 1.0 percentage points required in two years by the FRBM Act. 


In the same reference period, the reduction in fiscal deficit as a proportion of GDP was 1.2 percentage points, in excess of the minimum of 0.6 percentage points required in two years by the FRBM Act. However Dr Lahiri’s paper cautions that the deficit did not reflect a true and fair view of the Government’s finances as certain off-budget liabilities – viz. dues to Food Corporation of India (FCI) and issue of Oil Bonds/UTI bonds – were excluded from the definition of the deficit. 


Liabilities of the government in 2005-06 towards under-recoveries of oil companies was nearly Rs 57,000 crores (appx. $ 12.67 billion) in September 2006 which was expected to increase to nearly Rs 100,000 crores (appx. $ 22.22 billion) by the end of 2006.  Part of the liabilities were to be covered through oil bonds and the balance from the upstream producers ONGC, GAIL and OIL as transfers to the PSU downstream marketing companies. The amount to be shared between PSU companies was to be calculated in proportion to the after-tax profits of the company. 


If a company makes losses, it gets more. If a company makes profits, it is asked to give away more. Higher tax collections on account of high crude prices are an aberration especially when they cannot be justified by actual increase in subsidies.  They can, however, be justified if they are used to effectively to cushion the shock arising due to crude price volatility.


Oil bonds issued to cover these liabilities only postpone the resolution of the issue and also compound economic and financial costs.  As the oil bonds issued by the Government do not qualify for statutory liquidity ratio (SLR), they trade at a discount to a Government security of comparable tenor.


A recent Cabinet note from the Ministry of Petroleum & Natural Gas seeks extension of the subsidy scheme on domestic LPG (cooking gas) and PDS kerosene until 31 March, 2010.  The current subsidy scheme expires on March 31, 2007 and in the absence of an extension, the prices of kerosene and LPG will have to be raised sharply.


What is significant is that the ministry has sought that the Budget meets the full subsidy on these two products from next fiscal, against the existing norm of providing it on a flat-rate basis. Assuming crude oil prices at this year’s level, the finance ministry would have to set aside about Rs 28,600 crore ($ 6.4 bn) as subsidy on LPG and kerosene alone in Budget 2007-08. This will immediately impact the deficit targets under the Fiscal Responsibility & Budget Management Act.


Some Theoretical Perspectives 


In some developing countries domestic taxes on petroleum products provide a major source of revenue for the government.  The same governments also subsidize some of the products as a tool for redistributing income toward the low-income segments of the population. This is an important issue that has implications, not only for microeconomic or allocative efficiency but also for the design of macroeconomic policies.


The basic rule of public pricing could be stated as follows: set producer (input) prices at an efficient level and then choose appropriate level of taxes or subsidies based on equity criterion to get the consumer (final) prices right.  This rule is valid in a competitive economy in which profits or rents are adequately taxed and government fiscal policies are available to separate consumer and producer prices and to correct externalities, if necessary. 


However a number of features specific to the country make it undesirable to implement the basic rule indiscriminately.  In India for example, administrative and informational constraints, the government does not have the tax instrument necessary (e.g., VAT) to separate consumer and producer prices effectively. The role of direct taxes or transfers as a distributive mechanism is also very limited with the result that equity considerations are often of considerable importance in the design of indirect taxes in general and energy taxes in particular. 


Six different components that are considered while setting the price of petroleum products are given below:


P = p* + t1+ t2+ t3+ t4+ t5




P*            = Import Parity Price

t1             = Road user charges

t2             = Tax/ subsidy to address environmental externality

t3             = Tax / subsidy to reduce volatility in price

t4             = Tax / subsidy for re-distributional (equity) considerations

t5             = Tax for revenue considerations


Some theoretical studies that have examined the desirability and feasibility of fourth component t3, tax to reduce volatility in prices, in great detail suggest that the case for introducing the tax is weak. There is no economic case for t4 and t5 but when social and other concerns prevail, prudence would require that the t4, tax raised for re-distributional considerations on certain petroleum products consumed by economically stronger segments of the population are utilized exclusively for subsidising consumption of petroleum products consumed by weaker sections of the population.


ORF Centre for Resources Management is organising a focus group meeting on “What do falling crude prices mean for India’s Fiscal Deficit?” which intends to examine the following issues in the Indian context where heavy taxes on consumption of certain petroleum products paradoxically coexist with heavy subsidies for certain petroleum products. This meeting will be held on Thursday, 8th February 2007, at 10:30 AM, at ORF Campus. If you are interested in participating in the meeting please contact and confirm to:


Mr. Akhilesh Sati, Ph No. 4352 0020, Extn: 2102.


Issues for consideration


Should crude prices fall again as they have been doing what would be the net impact on the revenues to the Centre?


How may tax collections from the petroleum sector be managed so that they are in the long term rather than short-term interests of the economy in a situation where volatility in crude prices is expected to be the norm?


Shouldn’t transference of current liabilities to the future by way of bonds be the weapon of last resort?  Could the transparency in provisions for subsidies be improved? 


Aren’t policy makers introducing APM through the back door with continued manipulation of petroleum product prices without withdrawing the 1997 notification announcing the phasing out of APM between 1998 and 2002?   


How would India’s reform process progress when legacy issues continue to impede deregulation?


How could the petroleum tax regime be managed so that revenue mobilised may be utilised to provide fiscal incentives for the petroleum sector that is vital for the economy?




The Economics of Climate Change

Summary of Conclusions of the report “Stern Review: The Economics of Climate Change” by Sir Nicholas Stern, Head of the UK Government Economics Service and Adviser to the Government on the economics of climate change and development


There is still time to avoid the worst impacts of climate change, if we take strong action now.

The scientific evidence is now overwhelming: climate change is a serious global threat, and it demands an urgent global response. This Review has assessed a wide range of evidence on the impacts of climate change and on the economic costs, and has used a number of different techniques to assess costs and risks.

From all of these perspectives, the evidence gathered by the Review leads to a simple conclusion: the benefits of strong and early action far outweigh the economic costs of not acting. Climate change will affect the basic elements of life for people around the world – access to water, food production, health, and the environment. Hundreds of millions of people could suffer hunger, water shortages and coastal flooding as the world warms.

Using the results from formal economic models, the Review estimates that if we don’t act, the overall costs and risks of climate change will be equivalent to losing at least 5% of global GDP each year, now and forever.

If a wider range of risks and impacts is taken into account, the estimates of damage could rise to 20% of GDP or more. In contrast, the costs of action – reducing greenhouse gas emissions to avoid the worst impacts of climate change – can be limited to around 1% of global GDP each year.

The investment that takes place in the next 10-20 years will have a profound effect on the climate in the second half of this century and in the next. Our actions now and over the coming decades could create risks of major disruption to economic and social activity, on a scale similar to those associated with the great wars and the economic depression of the first half of the 20th century. And it will be difficult or impossible to reverse these changes.

So prompt and strong action is clearly warranted. Because climate change is a global problem, the response to it must be international. It must be based on a shared vision of long-term goals and agreement on frameworks that will accelerate action over the next decade, and it must build on mutually reinforcing approaches at national, regional and international level.

Climate change could have very serious impacts on growth and development.

If no action is taken to reduce emissions, the concentration of greenhouse gases in the atmosphere could reach double its pre-industrial level as early as 2035, virtually committing us to a global average temperature rise of over 2°C.

In the longer term, there would be more than a 50% chance that the temperature rise would exceed 5°C. This rise would be very dangerous indeed; it is equivalent to the change in average temperatures from the last ice age to today.

Such a radical change in the physical geography of the world must lead to major changes in the human geography – where people live and how they live their lives.

Even at more moderate levels of warming, all the evidence – from detailed studies of regional and sectoral impacts of changing weather patterns through to economic models of the global effects – shows that climate change will have serious impacts on world output, on human life and on the environment.

All countries will be affected. The most vulnerable – the poorest countries and populations – will suffer earliest and most, even though they have contributed least to the causes of climate change. The costs of extreme weather, including floods, droughts and storms, are already rising, including for rich countries.

Adaptation to climate change – that is, taking steps to build resilience and minimise costs – is essential. It is no longer possible to prevent the climate change that will take place over the next two to three decades, but it is still possible to protect our societies and economies from its impacts to some extent – for example, by providing better information, improved planning and more climate-resilient crops and infrastructure.

Adaptation will cost tens of billions of dollars a year in developing countries alone, and will put still further pressure on already scarce resources. Adaptation efforts, particularly in developing countries, should be accelerated.

The costs of stabilising the climate are significant but manageable; delay would be dangerous and much more costly.

The risks of the worst impacts of climate change can be substantially reduced if greenhouse gas levels in the atmosphere can be stabilised between 450 and 550ppm CO2 equivalent (CO2e). The current level is 430ppm CO2e today, and it is rising at more than 2ppm each year.

Stabilisation in this range would require emissions to be at least 25% below current levels by 2050, and perhaps much more. Ultimately, stabilization- at whatever level- requires that annual emissions be brought down to more than 80% below current levels. This is a major challenge, but sustained long-term action can achieve it at costs that are low in comparison to the risks of inaction.

Central estimates of the annual costs of achieving stabilisation between 500 and 550ppm CO2e are around 1% of global GDP, if we start to take strong action now. Costs could be even lower than that if there are major gains in efficiency, or if the strong co-benefits, for example from reduced air pollution, are measured.

Costs will be higher if innovation in low-carbon technologies is slower than expected, or if policy-makers fail to make the most of economic instruments that allow emissions to be reduced whenever, wherever and however it is cheapest to do so.

It would already be very difficult and costly to aim to stabilise at 450ppm CO2e. If we delay, the opportunity to stabilise at 500-550ppm CO2e may slip away.

Action on climate change is required across all countries, and it need not cap the aspirations for growth of rich or poor countries.

The costs of taking action are not evenly distributed across sectors or around the world. Even if the rich world takes on responsibility for absolute cuts in emissions of 60-80% by 2050, developing countries must take significant action too. But developing countries should not be required to bear the full costs of this action alone, and they will not have to.

Carbon markets in rich countries are already beginning to deliver flows of finance to support low-carbon development, including through the Clean Development Mechanism. A transformation of these flows is now required to support action on the scale required. 

Action on climate change will also create significant business opportunities, as new markets are created in low-carbon energy technologies and other low-carbon goods and services. These markets could grow to be worth hundreds of billions of dollars each year, and employment in these sectors will expand accordingly.

The world does not need to choose between averting climate change and promoting growth and development. Changes in energy technologies and in the structure of economies have created opportunities to decouple growth from greenhouse gas emissions. Indeed, ignoring climate change will eventually damage economic growth. Tackling climate change is the pro-growth strategy for the longer term, and it can be done in a way that does not cap the aspirations for growth of rich or poor countries.

A range of options exists to cut emissions; strong, deliberate policy action is required to motivate their take-up.

Emissions can be cut through increased energy efficiency, changes in demand, and through adoption of clean power, heat and transport technologies. The power sector around the world would need to be at least 60% decarbonised by 2050 for atmospheric concentrations to stabilise at or below 550ppm CO2e, and deep emissions cuts will also be required in the transport sector.

Even with very strong expansion of the use of renewable energy and other lowcarbon energy sources, fossil fuels could still make up over half of global energy supply in 2050. Coal will continue to be important in the energy mix around the world, including in fast-growing economies. Extensive carbon capture and storage will be necessary to allow the continued use of fossil fuels without damage to the atmosphere.

Cuts in non-energy emissions, such as those resulting from deforestation and from agricultural and industrial processes, are also essential. With strong, deliberate policy choices, it is possible to reduce emissions in both developed and developing economies on the scale necessary for stabilisation in the required range while continuing to grow.

Climate change is the greatest market failure the world has ever seen, and it interacts with other market imperfections. Three elements of policy are required for an effective global response.

The first is the pricing of carbon, implemented through tax, trading or regulation. The second is policy to support innovation and the deployment of low-carbon technologies. And the third is action to remove barriers to energy efficiency, and to inform, educate and persuade individuals about what they can do to respond to climate change.

Climate change demands an international response, based on a shared understanding of long-term goals and agreement on frameworks for action.

Many countries and regions are taking action already: the EU, California and China are among those with the most ambitious policies that will reduce greenhouse gas emissions. The UN Framework Convention on Climate Change and the Kyoto Protocol provide a basis for international co-operation, along with a range of partnerships and other approaches. But more ambitious action is now required around the world. 

Countries facing diverse circumstances will use different approaches to make their contribution to tackling climate change. But action by individual countries is not enough. Each country, however large, is just a part of the problem.

It is essential to create a shared international vision of long-term goals, and to build the international frameworks that will help each country to play its part in meeting these common goals.

Key elements of future international frameworks should include:

• Emissions trading: Expanding and linking the growing number of emissions trading schemes around the world is a powerful way to promote cost-effective reductions in emissions and to bring forward action in developing countries: strong targets in rich countries could drive flows amounting to tens of billions of dollars each year to support the transition to low-carbon development paths.

• Technology cooperation: Informal co-ordination as well as formal agreements can boost the effectiveness of investments in innovation around the world. Globally, support for energy R&D should at least double, and support for the deployment of new low-carbon technologies should increase up to five-fold. International cooperation on product standards is a powerful way to boost energy efficiency.

• Action to reduce deforestation: The loss of natural forests around the world contributes more to global emissions each year than the transport sector. Curbing deforestation is a highly cost-effective way to reduce emissions; largescale international pilot programmes to explore the best ways to do this could get underway very quickly.

• Adaptation: The poorest countries are most vulnerable to climate change. It is essential that climate change be fully integrated into development policy, and that rich countries honour their pledges to increase support through overseas development assistance. International funding should also support improved regional information on climate change impacts, and research into new crop varieties that will be more resilient to drought and flood.






International prices of Indian Basket Crude Oil and petroleum products



Indian Basket Crude Oil

Unleaded Petrol





Dollar per barrel


























April – June 2005







Retail selling prices at Delhi



Prices as on



PDS Kerosene

Domestic LPG

Rs. / Litre

Rs. Cylinder

1st April 2002





1st April 2003





1st April 2004





1st April 2005






4h May 2005






21st June 2005






Sources: 6th report, Pricing of Petroleum Products, Ministry of Petroleum & Natural Gas.




The New Politics of Global Warming

By Peter Brown


A political issue has reached critical mass when its natural adversaries throw in the towel.


That is what is happening in the United States on global warming, with President Bush and much of corporate America signaling they are through disputing whether temperatures are rising enough to portend future woes.


Of course, even if the disputes about the existence or potential ills of climate change are abating, that doesn't mean the global warming believers will now get the laws they want, or even find that candidates espousing their views win more elections.


In fact, the developing consensus that it is time to deal with the global warming problem rather than argue about its existence is likely to make it less, not more, of a salient domestic political issue.


It is worth remembering that when the Iron Curtain fell and the Cold Warriors claimed victory in the early 1990s, Americans elected a president, Bill Clinton, who was not one of them, and was short on national security credentials to boot.


That's because with the Soviet Union imploding at the time, voters figured they could move on to other matters. They then turned to the party they had been unwilling to trust with the White House when they were more worried about external threats.


So, while the new political environment -- no pun intended -- doesn't necessarily mean that Al Gore is going to be elected president just because he has been out front on the issue, it puts the politics of global warming in new perspective.


The acknowledgment by Bush of the problem and the need to deal with it is just one sign that the tide has turned on the climate change issue.


Recently, a number of major corporations that had been skeptical of the global warming threat have signaled they too want to move on to dealing with the problem.


And with Democrats -- who for years have campaigned against Bush and the Republicans as ignoring the global warming threat -- in control of Congress, it is obvious that something is likely to be done.


But the real question is exactly what that will be. It doesn't mean that Bush and corporate America are going to blithely agree to the ideas of the environmentalists on how to solve the problem.


Don't look for Bush to endorse the principal international treaty on global warming, the Kyoto Protocol. It doesn't require the same steps of China and India, which have the fastest growing and most polluting economies, as it does of Western industrialized nations.


The political argument now will be about the best way to combat the problem and its effects - in other words disputes about tactics and efficacy -- rather than larger, more fundamental disputes.


The environment has never been a huge issue to begin with, despite claims to the contrary by various interest groups. Yes, voters care about the environment, but they generally vote, especially for president, on other issues they consider more important i.e. -- national security and the economy.


With the existence of global warming no longer an issue, it is likely the political debate will shift to what steps and what resulting economic costs are reasonable. For instance, reducing emissions invariably increases the cost of energy, at least in the short run.


The current focus of debate will be the proposal advanced by many congressional Democrats and some Republicans for a "carbon tax" and an accompanying system that will allow companies to trade emissions credits.


Supporters call it a free-market solution without massive government interference, but the White House has not signed on to the idea despite some pre-State of the Union speculation that would be the case. It is not hard to see the political debate over the existence of global warming translating into the age-old dispute between the parties about the wisdom of taxes and regulation.


That is a much more complicated political discussion than whether the global climate is getting warmer, and how unless checked, the world could face rising oceans, melting glaciers, more violent storms, and droughts. And, it is one on which the political edge is not nearly as clear.


Peter A. Brown is assistant director of the Quinnipiac University Polling Institute.


Courtesy: Washington Post.







Chevron may bid for oil, gas blocks


January 24, 2007. US oil major Chevron Corporation may participate in the next round of bidding for oil and gas exploration blocks under the New Exploration Licensing Policy (NELP-VII). Chevron had last bid for oil assets in India during pre-NELP days and had no existing interest in the sector. No such clear indication is available on Chevron's participation in the next round of bidding for coal bed methane exploration blocks (CBM-IV). The company, however, has existing interests in CBM sector abroad. Though it has already reached an understanding with Reliance for jointly exploring investment opportunities in the upstream sector, a decision on any such participation would be taken once NELP-VII will be open for participation.


HPCL-Visakha erects CCR system


January 27, 2007. As a part of its clean fuels project, the HPCL-Visakha refinery in Visakhapatnam in Andhara Pradesh has safely completed the erection of the CCR cyclemax regeneration system and the CCR reactor. The Rs 2,147-crore ($ 486 mn) clean fuels project is intended to produce Euro II and Euro III fuels. The CCR system was erected by Technip KT India Ltd in five pre-fabricated modules, weighing 420 tonnes, and the height of the structure is 72 metres. It is one of the tallest structures in the refinery. It will enable the refinery to produce motor spirit with ultra low sulphur.


Oil companies' margins rise as crude falls


January 25, 2007. Though falling crude oil prices have yet to bring cheer to petrol and diesel users, they have led to hugely improved margins for oil marketing companies. Retail margins on transportation fuels are back to normal levels for Bharat Petroleum, Hindustan Petroleum and Indian Oil, after almost a full year of selling these products at a loss. Private sector player Reliance, which had almost exited the retail market, is also back with a 6 per cent share in December. Losses on the two cooking fuels, LPG and kerosene, continue to be high for the PSUs though. As of now, there seems to be little clarity on possible price cut for petrol and diesel.


Retail margins on diesel are currently around Rs 1.1-1.2/litre, while in petrol the sellers are making close to Rs 2.5/litre, according to industry sources. The prices have not been revised for the past several quarters in line with their cost. This pushed the oil marketing companies in the red. For the first six months of 2006, the oil marketing companies lost a total of Rs 38,000 crore ($8.6 bn). Around that time, the government came up with a subsidy-sharing scheme — which involved payouts from the upstream players and direct subsidy in the form of oil bonds from the government. Industry losses for the full year are estimated at Rs 52,000 crore.


RIL out of race for Aramco's $10-bn project



January 24, 2007. Reliance Industries Limited is out of race in bidding for building the $10 billion petrochemical complex in Saudi Arabia. The Saudi national oil company Saudi Aramco, has selected US major Dow Chemicals to partner it to construct own and operate a world scale chemicals and plastics production complex at the eastern province of Ras Tanura. RIL had submitted an expression of interest for the project. RIL could not get the award despite its strength and expertise to execute world-class projects without cost or time overruns.


The company currently boasts of world’s largest grass root refinery in single location. Exxon Mobil and Sabic were the other two petrochemical majors in the race to build the complex. The facility is proposed to be linked to Aramco’s existing refinery at Ras Tanura, which produces 30 million barrels of oil per day and is amongst the world’s largest refineries. The project cost has increased to about $10 bn (Rs 442 bn) from the originally estimated cost of $8 bn (Rs 353 bn), a year earlier. The complex is slated to produce a diversified slate of chemicals, and introduce new value chains and specialty products to the Kingdom.


The availability of these chemicals in the Kingdom is expected to facilitate the development of downstream conversion industries and the further industrialisation of the Kingdom. With proven oil reserves of 260 billion barrels, accounting for nearly one quarter of the world’s total reserves, Saudi Arabia also has the world’s fourth largest gas reserves. The country has signalled its ambitions to develop its petrochemicals and plastics industry, by establishing a joint venture with Sumitomo Chemical at the Rabigh refinery. It is believed that RIL company is expanding its capacities overseas to achieve a distinct market share in the world market. The company is planning to build 50,000 barrels per day refinery in Yemen. Besides, RIL is also exploring options for aggressively expanding its overseas ventures in Sudan, Colombia and Sri Lanka.


Oil refining firms line up $11.33 bn for up gradation


January 24, 2007. State-owned crude oil refining companies are lining up investments to the tune of Rs 50,000 crore ($11.33 bn) to upgrade their refineries, as part of the vision to make the country the “world’s refinery hub”. Ministry of Petroleum is of the view that Increased foreign interest in the refinery sector compels the refineres to upgrade to global standards. Indian Oil Corporation, the country’s largest downstream company, has a corpus of Rs 20,000-22,000 crore ($4.53-4.98 bn) for upgrading its existing refineries. The Fortune 500 company will now spend Rs 6,000 crore ($1.36 bn) to upgrade its refinery at Koyali, including the implementation of a delayed coker unit. The company has also lined up Rs 3,000 crore ($0.68 bn) for the 6 million tonne per annum Haldia refinery. Bharat Petroleum Corporation Ltd (BPCL) would spend Rs 2,000 crore ($453 mn) on implementing a delayed coker unit at the 7.5 million tonne per annum Kochi refinery.


The country’s state-owned refineries have a residue level of close to 30 per cent of the crude oil processed. This residue is primarily in the form of bitumen, used in making roads. The ministry of petroleum and natural gas is keen on state refineries upgrading their efficiencies to match international standards, according to which, the residue level is just around 10-15 per cent of the processed crude oil. IOC, which owns the largest number of refineries (10), including its subsidiaries Chennai Petroleum Corporation and Bongaigaon Refinery and Petrochemicals, has a refinery margin of $3-4 a barrel. Reliance Industries, which operates the 33 million tonne per annum Jamnagar refinery, recorded a $11 per barrel refinery margin in the October-December 2006 quarter. Refinery margin includes the cost of operating the refinery as well as profits of the refining company and is an indicator of its efficiency.


RIL plans Russian foray 


January 24, 2007. Reliance Industries Ltd is planning to set up a multi-billion dollar refinery cum petrochemical project in Russia. There was also a possibility of the company teaming up with Rosneft or Gazprom to jointly develop a oil and gas field in Russia. Setting up a gas or naphtha-based petrochem project in Russia to serve customers in Central Asia and Europe is still under discussion. There was a strong possibility that Reliance sets up a huge refinery and uses naphtha as a feedstock for the petrochemical project in Russia. Moscow has 41 oil refineries with a total crude oil processing capacity of 5.44 million barrels a day. However, many refineries are inefficient, ageing, and need upgrade. RIL may even acquire a refinery and upgrade it to meet the requirement of the feedstock-naphtha for its petrochem project.  

Transportation / Distribution / Trade


More cities to get GAIL gas supply 


January 24, 2007. State-run gas utility GAIL India has identified 28 cities for implementation of projects for supplying CNG to automobiles and piped cooking gas to households and commercial establishments. The cities identified include 13 polluted cities identified by the Supreme Court and the remaining on business viability basis. The Supreme Court had identified Agra, Lucknow, Kanpur, Varanasi, Pune, Faridabad, Patna, Ahmedabad, Sholapur, Hyderabad, Bangalore, Kolkata and Chennai as the most polluted.


Policy / Performance


Indian oilcos may get stake in Sakhalin-III


January 26, 2007. India and Russia are set to script a new energy chapter. The oil companies of the two fast-growing countries are working on a strategy that would give Indian companies a bigger stake in Russia’s vast oil reserves while their Russian counterparts get into the downstream refining and retailing segment in India. Petroleum minister Murli Deora, who met the Russian delegation, has pitched for a stake in Sakhalin-III, which is set to be auctioned in the coming months. In a quid pro quo strategy, Indian refining and marketing oilcos will hold talks with Gazprom and Rosneft under the joint working group to explore possibilities of Russian investment in India’s downstream sector. ONGC Videsh (OVL) is willing to take up to 49 per cent stake in Sakhalin-III. OVL has a 20 per cent stake in partnerhip with Rosneft in Sakhalin-I, is already importing crude cargoes from Russia.


Encouraged by the positive partnership in the Sakhalin-I project, Rosneft Oil Company of Russia and ONGC have decided to expand their relationship in other projects in Russia, India and third countries. An MoU to this effect was signed by the oil majors. This MoU in effect could mean that OVL and Rosneft may combine forces for a joint bid to acquire a stake in the Sakhalin-III field as and when it is auctioned.

As per the MoU, Rosneft and ONGC would jointly study the possibilities for mutual projects in exploration, production and marketing as well as other projects related to the hydrocarbon industry, including joint bidding for oil and gas stakes in Russia, India and third countries. The two companies also agreed to jointly explore the options for participation in refining and retail marketing projects in India, including integration of other companies in India. To implement this MoU, Rosneft and ONGC will establish two joint study groups, one of which will be responsible for upstream and the other for downstream.


Upon jointly identifying a project, the parties shall mutually decide on the structure of the joint venture to implement the identified project. ONGC will conduct the activities under this MoU in Russia and third countries through OVL. According to Rosneft, it would be ideal to match the growing Russian production with the growing Indian market through dedicated joint ventures. ONGC has a market capitalisation of $43 bn (Rs 1.9 trillion) while Rosneft has a market capitalisation of approximately $100 bn (Rs 4.4 trillion). OVL is currently engaged in 15 countries with 25 projects and 40 blocks.


Oil refining is viable by pre-empting tariff jumping


January 24, 2007. A clutch of international oil majors is reportedly seeking equity stakes in upcoming refinery projects in India. Oil refineries are large, capital-intensive projects, and the foreign direct investment on offer ought clearly to be welcomed. News reports say Saudi Aramco is in talks to pick up stake in Indian Oil’s Paradip refinery. Aramco is also seeking equity in HPCL’s Vizag refinery, as indeed is Total of France.


Further, in oil refineries across the land, in Mangalore, Bina, Bhathinda and elsewhere, international majors seem keen to acquire a substantial piece of the investment cake. In fact, the high effective tariffs on oil products is perverse incentive to do so. After all, the duty regime jacks up gross refinery margins across the board and hikes costs in the oil economy and beyond. In terms of policy initiatives, what is required is that we do away summarily with the duty differential between crude and products. Otherwise, we would be saddled with wholly high-cost oil assets.


In context of refinery economics the fact is that the value-added in oil refining is quite minimal, of no more than 10 per cent. So even a nominal duty differential between crude and products implies huge tariff protection for the value-added. This is quite unlike most other industries, where there is generally considerable value-addition downstream. Yet for long years, we have had a policy of high effective tariff protection for oil products purportedly to boost refinery projects. This has meant high duty differential between crude and refined products, and effective tariffs on products that have generally been over 50 per cent! And even in recent years, we have opted to have such a high-cost duty structure even as tariffs generally have been reduced. The recent expert committee on pricing and taxation of petroleum products, headed by Dr C Rangarajan, estimated the tariff protection for oil products at 40 per cent. Given the panoply of policy distortions in our oil sector, such as the effective ring-fencing of retail sales, the actual tariff levels would almost certainly have been much higher. In a voluminous industry like oil, such high tariffs are a glaring anomaly and guaranteed to give rise to needlessly high-cost refinery output.


The duties on petro-products have been pruned. While the import duty on crude is pegged at 5 per cent, that for products like diesel and petrol have been reduced, slightly, to 7.5 per cent, from 10 per cent. But despite the reduction in the duty differential last year, effective tariff protection for products remains upwards of 20 per cent given the lowly value-addition in oil refining.


The point is, compared to the prevailing tariff rates in the rest of the economy, the effective duty levels for petro-goods remains much too high. What is urgently required is that we remove the duty differential between crude and products once and for all. The logistics and sheer scale economies in shipping oil ought to be protection enough. A zero duty differential between crude and products would bring down untoward rents and stem gross refinery margins as well. And it would remove the perverse incentive to buy into Indian refinery assets to rake in rents propped up by policy fiat.


In a high-growth economy, oil refineries would be perfectly viable without policy prop-ups and sundry other sweeteners. Indian refiners can eminently do without high tariff protection on products. Instead, the watchword needs to be efficiency and sustained process innovation. Beyond ungainly high tariffs, the overall economic viability and efficiency of an oil refinery depends on the interaction of three key factors: the choice of crude oil used, the complexity of refining installations—refinery configuration—and the desired type and quality of products refined.

Additionally, refinery utilisation rates and environmental considerations also do affect refinery economics. For example, using more expensive crude oil (‘sweeter’, lighter) requires less refinery upgrading but supplies of light, sweet crude are at a premium and the differential in prices between lighter and more heavier crudes is seen to be increasing. Using cheaper heavier crude oil means more investment in refinery processes, sure. But the overall returns and payback can be substantially attractive with the right sourcing of crude and with proper refinery configuration. Additionally, the quality specifications of the final products are also increasingly important as environmental requirements become more stringent.  




Russia may build 10 N-power units in India


January 27, 2007. The fresh impetus to Indo-Russian nuclear power collaboration could see Russia building up to 10 nuclear units across various sites in India, subject to the progress made by the country in its forthcoming negotiations with the Nuclear Suppliers Group (NSG). Russia has already agreed to four additional units at Koodankulam atomic station, while six more units could be on the anvil across more sites. Over 100 Russian firms are already involved in the setting up of two under-construction 1,000-MW units in Koodankulam, most of whom are looking at bagging contracts from the proposed new projects since the Russian assistance comes with the caveat that the equipment has to be of Russian design. The projects would, however, be funded by India, which would have to bear the investment risks, including the threat of fuel supply disruptions.


The Russians are expected to carry out the draft documentation, supply equipment, construction and equipping process as well as train Indian operators at Russian enterprises and subsequently at the nuclear facilities. It is likely that the 1,000 MW `VVER-1,000' water-cooled reactors, being built at Koodankulam's under-construction station, could be used for some of the new units as well. There are close to 250 water-cooled reactors in use worldwide, of which 49 are Russian VVERs. The Koodankulam units have special devices that intercept, cool and localise core melt in case of an accident — a kind of concrete trap situated under the reactor. Besides, the units are protected from possible earthquakes, hurricanes, air crashes. The two existing units, located on the Indian Ocean coast, have already survived a tsunami, with the tidal waves being stopped by a special wave cutter.


Jayamkondam project by this year


January 26, 2007. The lignite major Neyveli Lignite Corporation (NLC) will execute the Jayamkondam Lingite Power Project (JLPP) this year and the State Government has initiated all steps to get the clearance from the Parliamentary Committee on Economic Affairs (PCEA) within six months. The project would be executed at an outlay of Rs 9,500 crore ($2.16 bn) with a capacity of 12 million tonnes of lignite excavation and a thermal plant of 1,500 MW in its first phase. While the primary work on excavating lignite would be taken up this year shortly after obtaining the green signal from the PCEA, the other on the power station would be taken up in January 2008.


Adani gp cuts tariff for 1,000-MW Gujarat project


January 25, 2007. Based on the lower rates offered by private power companies recently in the second and third round of bids under the new tariff-based policy, the government of Gujarat has managed to renegotiate the rate offered in the first round. Adani group which had submitted a rate of about Rs 3.25 per unit for supply of 1,000 MW power to the state under the Bid-1 process has revised it downward to Rs 2.89 per unit. In the Bid-1 round, four private sector companies had offered to supply a total of over 1,500 MW of power with a per unit rate in excess of Rs 3.2 per unit to the Gujarat Urja Vikas Nigam (GUVNL). This rate was much higher than the Rs 2.4 per unit that GUVNL got from Essar Power in the Bid-3 category recently.


Tata Power’s rate of Rs 2.26 per unit for the Mundra ultra-mega power plant was also much lower. In the Bid-2 round which was opened recently, the Adani group in consortium with the Vishal group offered a much lower Rs 2.35 per unit for the supply of another 1,000 MW of power to the state government. But, based on the highly-competitive rates received in the second and third categories, the state government has begun discussions with all the four players shortlisted in the first category to reduce their rates. While Adani group has already reduced its rates, the other three JSW Energy, Jindal Power and Chitrapur Coal and Power are yet to do so. Mr Patel claimed that Gujarat is the first state in India to have implemented the new tariff-based policy introduced by the Central Electricity Regulatory Authority (CERC). Gujarat has completed the process of tying up power supply to the tune of over 3,000 MW from private companies through this new policy.


Tata Power, Chhattisgarh ink MoU


January 24, 2007. Tata Power Company has signed a memorandum of understanding with the Chhattisgarh Government for a 1,000-MW plant in the State. The estimated cost of the project is Rs 5,000 crore ($1.13 bn). A preliminary feasibility study has identified Raipur district as suitable for the plant. A detailed feasibility study is in progress. The company was recently awarded a letter of intent for a 4,000-MW ultra mega power project at Mundra in Gujarat. It has signed MoUs with the governments of Orissa and Maharashtra for projects of 1,000 MW and 2,000 MW respectively.


Rosa Power on revival path as REL takes reins


January 24, 2007. The Anil Ambani-controlled Reliance Energy, which took over the Rosa Power project from the Aditya Birla group, has breathed fresh life into the long-pending project. REL has roped in IDBI Bank as the lead arranger of finance for the proposed 1,200 MW project at Shahjahanpur in UP. The Rs 5,500-crore ($1.25 bn) project’s debt-equity ratio has been fixed at 80:20. For the transportation of coal from Jharkhand to the project site — over a distance of 850 km, Rosa Power Supply Company (RPSCL) has signed a coal transportation agreement with the Indian Railways. The ministry of coal had already ensured a long-term fuel supply linkage for the project. Coal supply agreement is expected to be signed between RPSCL and Central Coal fields very soon. The coal will be supplied from Ashoka Mine in North Karanpura blocks of Central Coalfields, a subsidiary of Coal India. Water use agreement for the project, which will be catered by Garrah river, had also been signed with the state government.


The Rosa project, initially a 51:49 JV between the Aditya Birla Group and PowerGen of UK, was initiated in the early ’90s. The earlier estimates had pegged the project cost at Rs 2,603 crore ($591 Mn). However, the cost of the project had gone up with an indefinite delay in the project implementation. The project had also faced problems in coal linkage also. In November 2006, REL had taken over project and signed power purchase agreements (PPAs) with the state government. Due to the severe power shortage and the huge demand-supply gap, the government has approved the capacity upgradation proposal of the Rosa project from the initial 600 MW to 1,200 MW.

Construction work on the project will commence shortly as it is slated to be commissioned by 2010. The thermal plant has got mega project status. REL can sell electricity at the rate of Rs 2.69 per unit to Uttar Pradesh Power Corporation (UPPCL). The project, with a capacity of 1,200 MW, will generate about 9000 million units annually. Construction of the plant is expected to commence in March 2007. This is the second major investment into the state’s power sector after REL’s proposed 7,000 MW gas-based mega power project at Dadri with an investment of Rs 28,000 crore ($6.35 bn). The project is hanging fire due to lack of gas supply at an economical rate.  

Transmission / Distribution / Trade


Dabhol to produce electricity at Rs 2.83 per unit


January 28, 2007. The beleaguered Dabhol power plant in Maharashtra will produce electricity at Rs 2.83 per unit from June this year after the Government decided to use Petronet LNG Ltd's cheaper imported LNG to subsidise the plant's costlier fuel. The 1.5 million tons (24 cargoes) of LNG being sourced to meet Dabhol plant's short-term requirement (till September 2009) cost 10 to 10.5 dollars per million British thermal unit (delivered), resulting in generation cost of Rs 4.40 per unit. Since this is too high a price, Petroleum Ministry suggested pooling of price of short-term LNG being imported for Dabhol with Petronet's existing import of 5 million tons of LNG from Qatar. Currently, 5 million tons per annum of LNG being sourced by Petronet LNG from Qatar is sold to end consumers at around 4.6 dollars per mBtu. After pooling the two prices, the delivered cost of gas to Dabhol would be 5.73 dollars per mBtu (without customs duty on imported LNG) and 5.84 dollars per mBtu (with customs duty). The variable cost of electricity generation will be Rs 1.83 per unit and Rs 1.87 per unit respectively. Added to this would be Re 1 per unit fixed cost.


The Power Ministry wanted to sell electricity generated from Dabhol at Rs 3.40 per unit, using the incremental revenue to fund completion of LNG import and regassiciation terminal, adjacent to the power plant. The 5 million tons import facility needs Rs 3000 crore ($678 mn) to become operational but the Empowered Group of Ministers, earlier this month, shot down Power Ministry's idea. Petronet has been given the responsibility of procuring 1.5 million tons per annum of LNG on spot basis for 'short term' supplies (lasting up to September 2009). LNG will be re-gasified by PLL at its Dahej plant in Gujarat and gas would be transported through a new pipeline connecting Ratnagiri to Dahej. Ratnagiri Gas and Power Pvt Ltd (RGPPL), the new owner of Dabhol plant, will source long term LNG for the 2,184 MW power plant. RGPPL is owned by National Thermal Power Corp (NTPC) and GAIL (India) Ltd. The pool pricing would mean that Petronet LNG's existing customers will have to pay over 1.2 dollars per mBtu more from June/July this year.


Enzen, Analogic sign MoU to provide smart metering


January 25, 2007. Enzen Global Solutions and Analogic Technomatics have signed a memorandum of understanding to provide smart metering and billing solutions to power distribution companies in the country. While Engen Global expects to leverage its consulting expertise in energy and utilities sectors, Analogic would provide a wide range of hand-held computers and advanced metering and billing solutions.


 REL’s projects hit road block


January 24, 2007. Reliance Energy’s Transmission projects appears to have hit a bit of roadblock. Two projects-a joint venture with PowerGrid for the Parbati-Koldam transmission line and the Western Region System Strengthening Scheme II-could well be delayed. Reliance Energy Transmission, a subsidiary of Reliance Energy, won the bid for the Western Region System Strengthening Scheme II through a international tariff based competitive bid in November last year. The private transmission developer is yet to receive the letter of selection from the central transmission utility, PowerGrid (PGCIL). The letter of selection was due by the end of December. The Central Electricity Regulatory Commission has written to PGCIL asking it to issue the letter so as to ensure that the project is commissioned in time. RETL will have to apply to the central regulator for a license by mid-April. The project is to be commissioned by March 2010. As per the time schedule, the evaluation of transmission service charge and buy-out proposals followed by the issue of the letter of selection should have been completed by December-end.


Reliance Energy’s joint venture with Power Grid Corporation has been on hold since January last year. The Rs 738.3-crore ($167 mn) joint venture would construct two transmission lines connecting the 800 MW Parbati hydroelectric project being developed by NHPC and the 800 MW Koldam hydroelectric project being developed by NTPC. Reliance Energy was to have a 74 per cent stake in the JV. Though the two companies were to ink a joint venture agreement early last year, but the JV is yet to get off the ground. The shareholder’s agreement and other documentation leading to the formation of the joint venture company should have been issued within 45 days of the letter of selection, however that has not happened. According to Reliance Energy the delay was on account of certain issues relating to government policy.


KSEB signs pact to buy power from local body


January 24, 2007. The Kerala State Electricity Board (KSEB) has signed an agreement for purchase of power from a hydel project being established by Palakkad district panchayat. Meenvallam small hydel project, with an installed capacity of three megawatts, is the first of its kind being promoted by a local body in the State. The total cost of the project is estimated at Rs 10.86 crore ($2.46 mn). The National Bank for Agriculture and Rural Development (Nabard) will extend a loan of Rs 8 crore ($1.81 mn) towards the cost, while the three-tier panchayats in Palakkad district will mobilise the balance amount as capital. The power to be generated from the project will be purchased by KSEB at Rs 2.50 per unit in the first years and at Rs 2.12 per unit during the subsequent 20 years. The transmission lines to evacuate power from the generation plant have also been put in place. The project itself is slated to be commissioned within 18 months. The implementation of the project is entrusted with Small Hydro Company formed by the Palakkad district panchayat. The State-owned Steel Industrials Kerala Ltd (SILK) will execute the work on a turnkey basis.

Policy / Performance


India Power Fund to be operational by fiscal end


January 26, 2007. The Indian Power Fund, with an initial commitment of Rs 1,000 crore ($227 mn) will be operational before the end of this fiscal. Power Finance Corporation will invest about Rs 200 crore ($45.37 mn) in the fund. Oriental Bank of Commerce has agreed to invest Rs 10 crore ($2.27 mn) and LIC too has evinced interest to be part of the fund. It is proposed to register India Power Fund as a trust and a venture capital fund with SEBI with the objective of promoting trusteeship to supervise and administer the trust. As a part of this initiative, it is proposed to promote and incorporate an asset management company for the independent day-to-day management of the trust funds. It is proposed to step up funding in the increased liberal power scenario across the entire chain generation, transmission and distribution. The PFC, which is raising funds, expects to diversify its borrower portfolio by funding coal, lignite, oil and gas companies and infrastructure agencies that transport and handle fuel or power projects. The funding could also include bio-mass projects.


IFC to fund ultra mega projects


January 26, 2007. Washington-based International Finance Corporation (IFC) is in talks with Tata Power for facilitating long-term debt arrangement, along with other major ultra-major power projects. Besides, in the banking sector, it is looking at picking up equity stake and upper Tier-II instruments. The World Bank arm is looking at long-term funding opportunities in the range of $200-300 mn (Rs 8.82-13.22 bn) in ultra-mega power projects and is already in talk with Tata Power. IFC already has a big-ticket exposure of over $100 mn (Rs 4.41 bn) in Tata Steel and Cairn Energy. Exposure to India is the fourth-largest after Russia, Brazil and Turkey.


Power min seeks to streamline duties


January 26, 2007. The ministry of power has called for rationalisation of duties in the power sector. It has suggested reducing excise duty from the present rate of 16 per cent to 8 per cent. On the Customs duty front, it has asked for a rationalisation of six different duty structures to two-one for mega power projects and the other for non-mega power projects. The ministry of power has argued that neither Cenvat nor modvate can be levied on electricity as it is not a good on which excise can be levied. Hence, the excise duty should be reduced from the present level of 16 per cent to 6 per cent and countervailing duties should be aligned accordingly.


On rationalising Customs duty, the ministry has argued that while mega power projects attract 0 per cent Customs and countervailing duties, transmission projects associated with these projects are levied a 10 per cent Customs duty and a 16 per cent CVD. The ministry would like the concessional zero Customs duty regime to be extended to transmission projects associated with the mega power projects. This would also include the ultra-mega power projects, as the mega power project tax structure applies to these projects as well.


For projects other than the mega power projects, the ministry has suggested that imports required for initial setting up or expansion of projects, renovation & modernisation, capital goods for generation, spares, transmission, subtransmission and distribution should attract a Customs duty of 5 per cent and countervailing duties of 8 per cent. At present, spares are levied a Customs duty of 12.5 per cent and 16 per cent CVD while transmission, sub-transmission and distribution attracts a Customs duty of 10 per cent and CVD of 16 per cent.


Cabinet nod to WSEB bifurcation


January 25, 2007. The bifurcation of the West Bengal State Electricity Board was approved by the state Cabinet as part of the restructuring of the power sector. West Bengal became the 16th state to implement restructuring in line with the requirement of the Electricity Act, 2003. The move was to improve commercial efficiency and enhance levels of customer service on a sustained basis. The two new government companies would be in place by April 1, but the final transfer scheme would be formulated within one year after closure of accounts of the West Bengal State Electricity Board for 2006-07. The West Bengal State Electricity Transmission Company Ltd would look after transmission and state load dispatch functions while the distribution and hydro-business were vested with the West Bengal State Electricity Distribution Company Ltd. Both companies are in the process of incorporation.   





BP to spend up to $2.4 bln in San Juan Basin


January 30, 2007. BP Plc plans to spend up to $2.4 bn over the next 13 years to increase its coalbed methane natural gas production in the San Juan Basin in southwestern Colorado. The company said the project will raise its ultimate recovery from the basin by about 1.9 trillion cubic feet of coalbed methane natural gas. It will raise BP's net production in the basin, currently 425 million cubic feet per day, by over 20 percent. The project, which includes funding for the drilling of more than 700 new wells, will allow it to keep production in the basin above present levels for more than a decade. The San Juan Basin has attracted numerous energy producers in recent years as advances in drilling technology have made the gas reserves there more economical to tap, replacing many of the other U.S. fields that are quickly emptying.


Iran signs LNG pact with Repsol, Shell


January 29, 2007. Iran has signed a preliminary agreement with Spain's Repsol and Royal Dutch Shell to produce liquefied natural gas from its South Pars gas field. The contract is the biggest project in terms of investment and the volume of gas converted to LNG. The final decision on the investment, which the agency valued at $10 bn, would be made by the end of 2007.


The upstream work of phases 13 and 14 (of South Pars field) will be carried out on buyback terms. The Anglo-Dutch firm Shell and Repsol would each have a 25-per cent share while Iran maintained a 50 per cent share in the project aimed at producing an annual 16 million tons of LNG.

Iran's buyback system skirts around the constitution, which prohibits foreign companies from taking equity stake in its oil and gas sector. Instead, it enables foreign companies to develop a project for a set time, after which they are paid by the government in oil or gas revenues at market prices. Iran sits on the world's second largest reserves of natural gas after Russia but faces investment problems in developing the fields.

US oil firm to raise funds for Vietnam gas project


January 28, 2007. American Technologies Inc. would list 20 percent of its oil and gas unit ATI Petroleum's shares on the Euronext stock exchange to raise around $200 mn for a natural gas project in Vietnam. ATI Petroleum had made a gas discovery at the Yen Tu field off Vietnam's north coast. The gas block, called Thai Binh and located 70 km (44 miles) off the port city of Hai Phong, has estimated reserves of 1 trillion cubic feet of gas. Tests at the block showed a gas flow of 47 million feet per day. If all goes well we hope to put the gas field into commercial production by 2009. The company plans to build a pipeline with state oil monopoly Petrovietnam to deliver the gas from the field to power plants in northern Vietnam.


Oil firms eye new frontier in Angola's Cabinda


Jan 28, 2007. Australia's Roc Oil will begin exploring for oil in Cabinda later this year, while a group led by U.S.-based Devon Energy Corp  and including Portugal's Galp is also planning onshore exploration. Others are expected to join the fray to stake a claim to what could become Angola's next oil frontier. Cabinda's offshore oil wealth already accounts for between 50 and 65 percent of the 1.4 million barrels of oil produced each day in Angola, sub-Saharan Africa's second largest petroleum producer after Nigeria. Production in the southwestern African nation is expected to rise to 2 million barrels a day by the end of this year, and Cabinda's offshore drilling is expected to account for much of that jump. Neither the Angolan government nor foreign oil companies have a clear idea of the potential impact of onshore drilling in Cabinda. There has not been any drilling onshore for 34 years.


Gazprom approaches Shtokman bidders as contractors


January 26, 2007. Russian gas export monopoly Gazprom has offered possible contract work on its huge Shtokman project to the five companies that previously bid unsuccessfully for a stake in the scheme. Talks with the five companies will start in February. Last year Gazprom stunned the five hopefuls -- French oil major Total, Norway's Statoil and Norsk Hydro and U.S. majors ConocoPhillips and Chevron by scrapping a year-long bidding process and saying it would develop Shtokman without any foreign equity partners. Energy analysts were dismayed by the move, saying Gazprom would struggle to complete the $20 bn project, under the stormy and iceberg-strewn Barents Sea, without foreign know-how. Gazprom would use foreign contractors but would not offer them any equity in the project, which envisages piping some Shtokman gas to Europe and liquefying the rest for shipping to the United States. Statoil and Norsk Hydro both have regular "business dialogue" with Gazprom. Both companies, which have deep-water drilling and logistics experience in the Arctic, still see opportunities in Russia despite the Shtokman snub. Recently Norway's oil minister called on Moscow to jointly develop a petroleum strategy for the Arctic, which may hold a quarter of the world's undiscovered oil and gas resources. Shtokman, 550 km (342 miles) from Russia and Norway, has reserves of more than 3.7 trillion cubic metres of gas.


New gas discovery in the Black Sea, Turkey


January 26, 2007. Stratic Energy Corporation and its joint venture partners TPAO (the Turkish national oil company) and Toreador Resources Corporation have sixth gas discovery in the South Akcakoca sub-basin in the Black Sea, offshore Turkey. The Akcakoca-4 well, which was drilled using the Attwood Southern Cross semi-submersible rig as a deviated well from the same surface location as the recent Akcakoca-3 well, tested a separate structure (named Akcakoca East) on the same geological trend. The new discovery is located to the east of the recent Akcakoca discovery and to the north of the Ayazli, Dogu Ayazli and Akkaya discoveries, which are currently under development with first gas expected in the current quarter. Stratic's share of the discovery is 12.25 per cent. The Akcakoca East discovery well encountered approximately 37 meters of gas-bearing sands in three zones between 1,159 and 1,375 meters true vertical depth. The lower zone, with approximately 13 meters of net pay, tested at a flow rate of 8.6 million cubic feet of gas per day with a flowing pressure of approximately 630 psi on a 48/64-inch choke. Operations to test the upper zone will commence shortly.


The original schedule for the Southern Cross involved a break in the drilling sequence after the current well to allow the rig to be used for a 3-4 month period by another operator. The Akcakoca partnership has negotiated with this operator to retain the rig for one more slot to accelerate the drilling of the next well in the sequence, on the Guluc prospect, which will now be drilled immediately after testing is completed on the Akcakoca-4 well. Once operations on the Guluc-1 well are complete the rig will be released to the other operator.


The Guluc prospect, which is the largest individual prospect identified in the South Akcakoca sub-basin, is on a separate fault block further east along the Akcakoca fault trend. To drill Guluc-1 the rig will be moved approximately 2.5 kms to a new surface location. Early information on the Guluc prospect is critical in determining the optimum development plan for the deeper water area.

Chevron discovered oil offshore Angola


January 26, 2007. Chevron Corporation’s subsidiary Cabinda Gulf Oil Company Limited (CABGOC) and partners achieved a significant oil discovery in deepwater Block 14, offshore Angola. The discovery well, Lucapa-1, was drilled in October 2006 in 3,940 feet (1,201 meters) of water to a total vertical depth of 10,958 feet (3,340 meters) and encountered more than 280 net feet (85 net meters) of oil in Miocene-age sands. The well was tested in November at commercial rates from high- permeability sand in the main target area. The discovery will be followed by further drilling in addition to geologic and engineering studies to appraise the field and assess its potential reserves. The Lucapa discovery is the 10th exploration discovery made in Block 14 since 1997.


Chevron is among the largest producers of energy in Angola, and is operator in Blocks 0 and 14, which generate more than 500,000 barrels of oil-equivalent daily gross production. Among the major projects under development is the Benguela Belize-Lobito Tomboco (BBLT) project in Block 14, which started-up in January 2006. This $2.3 bn project, when fully developed, will produce an estimated total daily maximum of 200,000 barrels of crude oil in 2008. In June 2006, Chevron achieved first oil from the Landana North reservoir in the Tombua-Landana development area of Block 14 by producing through the BBLT facility. When fully developed, Tombua-Landana is expected to achieve peak production of approximately 100,000 barrels of crude oil per day by 2010 through its own facility.



Tesoro to buy Wilmington refinery


January 29, 2007. The oil refiner Tesoro Corp. will buy a Los Angeles-area refinery and 250 Southern California retail sites from a division of Royal Dutch Shell PLC for $1.63 bn. The company’s board approved the deal with Shell Oil Products US. The sale is subject to regulatory clearance. The price does not include the value of petroleum inventory that will also be acquired when the deal closes. That is expected to be up to $200 mn. Besides the Wilmington refinery, the deal includes Shell's Wilmington products terminal. San Antonio-based Tesoro signed a long-term agreement that will keep the retail sites, each of which averages sales of 225,000 gallons per month, under Shell's brand name. The deal will be completed in the second quarter of this year. The Los Angeles refinery processes heavy, sour crude. Tesoro currently operates six refineries with a total capacity of 560,000 barrels per day. Tesoro's retail system includes 450 branded retail stations, with 200 of those operating under the Tesoro and Mirastar brands. Shell's Wilmington refinery has a capacity of about 100,000 barrels per day.

Transportation / Distribution / Trade


FERC OKs Kinder Morgan natgas pipeline


January 26, 2007. According to the Federal Energy Regulatory Commission Kinder Morgan Energy Partners' proposed Louisiana Pipeline would do little harm to the environment, and thus the project is moving a step closer to final FERC approval. The 135-mile (217 km) pipeline would be able to transport about 4 billion cubic feet of natural gas a day from the Sabine Pass liquefied natural gas terminal into the national pipeline and underground storage grid. The $500 mn project would deliver gas to 10 existing interstate pipelines and one pipeline within Louisiana. Such broad access to markets in the Gulf Coast, Northeast, Mid-Atlantic, South, Midwest and Southeast through multiple pipeline connections would allow shippers to redirect supplies as pipeline capacity is available. Kinder Morgan plans to build the pipeline in phases, with construction set to begin this November and the project initially brought into service by October 2008 and completely operating by April 2009.


McDermott awarded Russian pipeline contract


January 26, 2007. J. Ray McDermott, S.A. was recently awarded a sub-sea pipeline installation project by Lukoil-Nizhnevolzhskneft, LLC, a subsidiary of OJSC LUKOIL Oil Company, for the Yuri Korchagin field which is located 180 kilometers outside Astrakhan city in the Russian sector of the Caspian Sea. For more than 20 years J. Ray has undertaken a number of projects in the Caspian Sea and in Russian waters. J. Ray will install a 58 kilometer 12" oil pipeline, which will connect the ice-resistant fixed platform No.1 (LSP-1) to a single point mooring south of the Yuri Korchagin field. Under the contract J. Ray will also provide design engineering, procurement, installation and testing of the sub-sea pipeline, with project support from J. Ray's facilities in Azerbaijan and the United Arab Emirates.


Shanghai to get LNG supply from Malaysia


January 24, 2007. Shanghai has started construction of a 4.6 bn yuan liquefied natural gas (LNG) terminal that will start receiving the fuel from Malaysia in 2009. The plant will return three million tonnes a year of LNG to gas form during its first phase. Shenergy Group, owned by the city government, and partner China National Offshore Oil Corp are building the project. The world’s biggest energy user after the US, China in October agreed to buy $25 bn of LNG over 25 years from Malaysia. China wants to increase consumption of natural gas to 8 per cent of its energy needs in 2010 from about 3 per cent to cut pollution and reliance on coal and oil. Petroliam Nasional Bhd (Petronas) would start supplying an initial 1.1 million tonnes of LNG a year starting in 2009. Petronas would increase the supply to three million tonnes, equivalent to four billion cu m, in 2012. Natural gas supplies to Shanghai may reach six billion cu m by 2010.

Policy / Performance


Iran moots OPEC style gas group with Russia


January 29, 2007. Iran and Russia could start up a gas exporting group like OPEC based on their command of the world’s largest natural gas reserves, Iranian Supreme Leader Ayatollah Ali Khamenei said. Forming a grouping of producers to control gas prices has been mooted in the past but officials in gas producers, including Russia, have tended to play down its prospects, partly because the gas market is dominated by long-term contracts. Russia and Iran are the world’s No. 1 and No. 2 holders of gas reserves respectively. Iran’s reserves are estimated at 940 trillion cubic feet or more and Russia’s is estimated to hold between 1,680 trillion to 2,360 trillion cubic feet. World reserves are estimated by industry experts at between 6,100 trillion and 7,000 trillion cubic feet.


The European Union, which relies on Russia for about a quarter its gas imports, expressed concern that Russia and Algeria, another major supplier of gas to the EU may create a gas cartel that could hurt EU consumers. Russia has repeatedly denied to have any plan to form a cartel. While Russian gas monopoloy Gazprom says its long-term contracts make such a suggestion implausible. Despite its large gas reserves, Iran has been slow to develop exports, partly because U.S. sanctions hinder Tehran’s access to the most commonly used technology for making liquefied natural gas (LNG), a product which can be exported by ship. Algeria has also said talk of forming a group of gas producers, like the Organisation of the Petroleum Exporting Countries, is premature.


Iran, India, Pakistan agree on gas pricing formula


January 26, 2007. Iran, India and Pakistan have agreed on a pricing formula for the export of Iranian gas to meet India's burgeoning energy demands. The three sides will take this proposal, this agreement to their governments and will take the next steps after their governments give their opinions. The three sides have one month to respond. Talks on the proposed multi-billion-dollar pipeline- to supply Iranian gas to India through a 2,600-kilometre (1,600-mile) pipeline via Pakistan- began in 1994. The talks stalled due to tensions between South Asian rivals India and Pakistan but were re-started following the launch of a slow-moving peace process in February 2004 on eight contentious issues including the divided Himalayan region of Kashmir. The discussions then ran into another obstacle, with Tehran saying New Delhi and Islamabad were unwilling to pay the asking price. In August, the three countries agreed to appoint a consultant to resolve the row over the fees. Indian oil ministry said the price quoted by Tehran was about seven dollars per million British thermal unit of gas which includes the cost of transportation. New Delhi, which is anxious to exploit new sources of energy to fuel its booming economy, deemed this too steep and was unwilling to pay more than 4.25 dollars per unit.


U.S. will need Mideast oil for years to come: Saudi


January 24, 2007. On the eve of U.S. President George W. Bush's address to Congress which is expected to tout the need for more U.S. energy independence, Saudi Arabia's U.S. ambassador said that the world's biggest oil user will rely on Middle East crude oil “for many years to come”. Bush's annual State of the Union address is expected to touch on key energy policy points after Bush made the surprise pronouncement during last year's address that the United States is addicted to crude oil, including supplies imported from the Middle East. However, U.S. policymakers should be talking about interdependence with Middle East suppliers, not independence, said Prince Turki Al-Faisal, the kingdom's U.S. ambassador. Saudi Arabia is the world's biggest crude oil producer and the linchpin of the OPEC producer group, which pumps over a third of global oil supplies.


A rising focus on "energy security" by both the Bush administration and Congress has added momentum to efforts to employ home-grown fuel sources like ethanol to reduce U.S. dependency on oil imports. About 60 percent of U.S. petroleum supplies come from imports currently. Following that theme, Bush is likely to call for more U.S. usage of home-grown supplies of ethanol. Bush's speech could call for over 60 billion gallons (227 billion liters) a year of ethanol to be mixed into U.S. gasoline supplies by 2030 - or about 30 percent of current U.S. gasoline consumption. According to Energy Department a conservative limit of ethanol from corn is about 13 billion gallons. But the Bush administration wants to make ethanol production from cellulosic materials like wood chips cost-competitive with corn-based ethanol by 2012, allowing for greater renewable fuel use.


Senate Energy Committee Democrats unveiled five-part energy bill, which would reduce U.S. petroleum imports by 40 per cent by 2020 through more efficient vehicles, renewable fuel sources like ethanol, and requiring 15 per cent of U.S. electric supplies to come from renewable sources by 2020. The U.S. economy will continue to rely on crude oil imports- which currently account for more than half the nation's oil consumption.





Tampa Electric seeks bids for new power plant


January 26, 2007. Tampa Electric aid a process outlining the company's future power needed and identifying the company's proposed projects. The request for proposal process would allow Tampa Electric to pick the most cost-effective method of providing power. The company's current plans call for a self-build option for a facility that would be operational in 2013 on the site of the existing Polk Power Station in Polk County. The new facility would be a 630-MW "integrated gasification combined cycle" plant, a process that uses gas derived from coal to generate electricity, then uses the hot gas leaving the turbine to heat water and produce steam to power a steam turbine and generate more electricity. The request for proposal solicits competitive bids and widens the alternatives to building the plant.


Hunton Energy for $2.4 bn Clean Energy Power Plant


January 24, 2007. Hunton Energy, a Texas-based independent power producer, developing a new power generation plant slated to provide clean energy at lower costs to area schools, hospitals and local Fort Bend County government entities. The estimated $2.4 bn (Rs 106 bn) Lockwood IGCC Plant will consist of two phases with the first phase scheduled for a 1Q 2008 groundbreaking. The plant will use patented processes to gasify a petroleum byproduct, ultimately generating 1200 MW of power with some of the lowest negative emissions of any plant in the USA. An integrated gasification combined cycle (IGCC) power generation configuration is a clean, efficient means of producing electricity from coal or petroleum residues such as "pet coke." The Lockwood Plant will use pet coke as its primary fuel; pet coke (petroleum coke) is a refinery byproduct with properties similar to coal. Protecting the environment by lowering carbon dioxide (CO2) emissions is also a goal of Hunton Energy. The Lockwood Project will verify that it is possible for this country to have lower and more stable electricity costs, lower emissions and CO2 sequestration, all at the same time.


According to the latest U.S. Department of Energy figures, independent power producers- such as Hunton Energy- are providing more than 25 per cent of the nation's energy needs. Hunton Energy is a privately-owned independent power producer headquartered in Houston. The company's efforts are focused on clean energy and gasification technologies. Hunton Energy's management has more than 30 years experience in independent power production, energy marketing and asset development.


Transmission / Distribution / Trade


AGL to buy CLP’s power plant for A$417 mn


January 30, 2007. Australia's biggest energy retailer AGL Energy plans to buy a power plant for A$417 mn (Rs 14.18 bn) from TRUenergy, a subsidiary of Hong Kong-listed CLP Holdings. The 1,280 MW gas-fired station on Torrens Island is the largest power station in South Australia. In addition, as part of the transaction AGL aims to sell its 180 MW gas-fired peaking plant at Hallett, South Australia, for A$117 mn (Rs 3.98 bn) to TRUenergy, resulting in a net price for Torrens Island power station of A$300 mn (Rs 10.2 bn). The acquisition will boost AGL's generation capacity by 68 percent, allowing it to better manage its retail and industrial and commercial customer positions in both gas and electricity across Australia's entire eastern seaboard market. The deal is subject to approval by the Australian Competition and Consumer Commission.


Power sales to India to fuel Bhutan's growth


January 26, 2007. Bhutan's economy is projected to power to a 12 per cent GDP growth in 2007, almost entirely on account of increased electricity sales to India with the new Tala hydroelectric project going on-stream. The economy of the Himalayan kingdom, which is estimated to have grown by a robust 10 per cent in the year 2006, is slated to witness a 12 per cent growth in 2007 as the 1020 MW Tala project reaches full production by around May this year. In fact, even prior to the Tala hydroelectric project getting commissioned, Bhutan's economy relied heavily on hydropower revenues from India, which accounted for some 12 per cent of the country's GDP and 45 per cent of national revenues in 2005-06. The pre-Tala hydropower revenues were mainly from electricity supplies from the 336 MW Chukha hydro project and the 60 MW Kurichhu Hydro Project to India. The Tala hydroelectric project is, by far, the largest hydro project in Bhutan. The phased commissioning of six 170-MW generating units of the Rs 4,124-crore ($0.94 bn) project (from August 2006 through to May 2007) is expected to double Bhutan's annual power exports, generating about $1 mn a day. GDP growth has been consistently growing from about 8 per cent in 2005 by about 2 percentage points each of the two subsequent years. In fact, during the full year, Tala's operations could raise the share of hydropower dividend revenues to total budget revenues from the current 45 per cent to 60 per cent. With substantially larger exports, the current account deficit should decline to about 9 per cent in 2006 and then move into surplus in 2007.


Besides the Tala project, Bhutan and India are jointly taking up three more projects totalling 2,532 MW in Bhutan. While the Tala project is expected to move to the top of Bhutan's revenue sources from this year on, so far Chukha Hydro Power Corporation Ltd (which runs the Chukha project) has been the foremost source of revenue for the exchequer. Chukha ranks even above the Royal Monetary Authority of Bhutan, the top bank of the kingdom, in terms of revenue inflows.


PowerGrid in talks with US firm


January 24, 2007. Power Grid Corporation of India Ltd (PGCIL) has initiated talks with American Electric Power (AEP), an electric utility in the US, to explore the possibility of forming a strategic alliance for executing transmission projects in that country. The proposed alliance with one of the leading power sector company in the US would provide an opportunity for PGCIL to enter into high technology area in US.  The US grid has suffered from under-investment for a long time, but with the enactment of the Energy Policy Act 2005, the Federal Energy Regulatory Commission has finalised rules to boost investment in the ageing transmission infrastructure. AEP owns nearly 36,000 MW of generation capacity and 39,000 mile of transmission network in the US.

Policy / Performance


China eyes 840 GW power capacity by ’10


January 30, 2007. China expects its installed power generating capacity to grow by around one third to 840 gigawatts by the end of the decade. China’s new capacity nearly equivalent to the whole generating ability of France or Germany and it needs expansion to keep pace with the needs of its breakneck economic growth. The forecast increase, spread over three years, would represent a slowdown from 2006's frenetic 20 percent growth to 622 GW, and would leave China lagging far behind the United States, which already has over 1,000 GW of capacity. The portion of coal burning plants would slip slightly to around 70 percent, or 593 GW, while hydropower would be 190 GW. Wind generation will rise to 5 GW, biomass will be 5.5 GW, nuclear 10 GW and natural gas a modest 4 percent or 36 GW, under the forecast which sees GDP growth of around 8.5 percent. China officially aimed to reach 650 GW of capacity by the end of the decade but booming economic growth pushed up demand far more rapidly than planners had anticipated. China will shut down small coal power stations and stop new small stations over the next four years in a drive to raise energy efficiency and cut pollution. Many smaller stations produce less than 50 megawatts of electricity.


California may ban conventional lightbulbs by ’12


January 30, 2007. A California lawmaker wants to make his state the first to ban incandescent lightbulbs as part of California's groundbreaking initiatives to reduce energy use and greenhouse gases blamed for global warming. Incandescent lightbulbs were first developed almost 125 years ago, and since that time they have undergone no major modifications. Meanwhile, they remain incredibly inefficient, converting only about 5 percent of the energy they receive into light. Lloyd Levine, California Assemblyman, is expected to introduce the legislation this week. If passed, it would be another pioneering environmental effort in California, the most populous U.S. state. It became the first state to mandate cuts in greenhouse gas emissions, targeting a 25 percent reduction in emissions by 2020.


Compact fluorescent lightbulbs (CFLs) use about 25 percent of the energy of conventional lightbulbs. Also, CFLs generate 70 percent less heat than incandescent lights. Many CFLs have a spiral shape, which was introduced in 1980. By 2005, about 100 million CFLs were sold in the United States, or about 5 percent of the 2-billion-lightbulb market. About a fifth of the average U.S. home's electricity costs pays for lighting, which means even if CFLs initially cost more than conventional lightbulbs, consumers will save. A 20-watt CFL gives as much light as a 75-watt conventional bulb, and lasts 13 times longer. An average home in California will save $40 to $50 per year if CFLs replace all incandescent bulbs.


IPPs to generate 13.4 GW power by ’16


January 30, 2007. Around 50 projects in the private sector in Pakistan are in the pipeline to generate 13,400 MW of electricity by 2016 at an estimated cost of $12.847 bn (Rs 566 bn). Giving year-wise details of the Independent Power Plant projects, the Water and Power Ministry said 10 projects with 2,255MW capacity, including six oil and four pipeline quality gas dual-fuel, are expected to be completed by 2008 with an investment of $1.691 bn (Rs 74 bn). Out of the six oil projects during 2008, the main project is the capacity expansion from the existing IPPs near Lahore with 405 MW capacity.


This project would cost $304 mn (Rs 13.39 bn). Similarly, during 2009, eight projects have been planned to generate 1,764 MW electricity with an investment of $1.323 bn (Rs 58 bn). These include three oil and five dedicated gas field projects. In 2010, seven projects of 1,321 MW capacity, including two hydel, one oil, three pipeline quality gas dual-fuel and one dedicated gas field would be completed with a cost of $1.096 bn (Rs 48 bn).


Likewise, in 2011, three hydel projects with generating capacity of 284 MW, costing $355 mn (Rs 15.63 bn) would be completed. Further in 2012, seven projects having a capacity of 2726 MW, including three hydel and four coal projects would be completed with a cost of $2.320 bn (Rs 102 bn). In 2013, five projects, including four hydel and one coal would be completed to generate 1,986 MW electricity.


These projects will cost $2.233 bn (Rs 98.34 bn). Three hydel projects having 1,443 MW capacity are likely to be completed in 2014 with a cost of $1.804 bn (Rs 79 bn). Similarly, in 2015 and 2016 seven hydel projects are planned to generate 1,620 MW electricity and would cost $2.025 bn (Rs 89 bn). To meet growing power needs of the country, recently five agreements have been concluded with different parties for generation of about 1,300 MW electricity. Power projects with a total capacity of 6,000MW are in different stages of approval. These include 550 MW of wind power projects.


Exxaro starts building new coal mine


January 30, 2007. Exxaro Resources had started construction of a new coal mine costing R245 million in start-up capital in South Africa. The Inyanda mine in Mpumalanga would produce 1 million tons of A-grade thermal coal annually for the export market. It is expected to start full production in 2008.


China's coal-to-liquid plant eyes 2010 expansion-Report


January 28, 2007. China's largest coal producer, the Shenhua Group Co. Ltd., plans to expand its first coal-to-liquids plant to 6 million tonnes a year by 2010. The firm aims to start the first phase of the giant project, in northern China's Inner Mongolia, by the end of 2007. When completed, this phase, costing 24.5 bn yuan ($3.15 billion), would produce 3.2 million tonnes of liquid fuels a year. China, the world's second-largest oil-user and seeking to cut its growing dependence on imports, expects the project to meet a tenth of its needs by 2020. Shenhua Group is the parent of Hong Kong-listed Shenhua Energy Co. Ltd.


Renewable Energy Trends


Washington state aims to build biofuels industry


January 30, 2007. Washington state legislators are considering a bill to promote a biofuels industry in the state and require state-owned fleet vehicles to reduce use of fossil fuels. In Oregon, Democratic Gov. Ted Kulongoski is pushing a "global warming initiative" in the Legislature that includes reduced greenhouse gas emissions, more renewable energy sources, biofuels, and tax credits to spur energy research and development.


The moves in the Pacific Northwest states mirror California's pioneering "green" programs to cap emissions of gases linked to global warming, expand the use of low-carbon vehicle fuels, and require gas and electric utilities to increase supplies of wind, solar, biomass and other renewable energy sources. The three West Coast states are cooperating on a series of environmental initiatives, including standards to reduce car and truck tailpipe emissions and efforts to promote energy efficiency and reduce pollution from power plants. The chairmen of public utilities commissions in Washington, Oregon, California, and New Mexico adopted a "Joint Action Framework on Climate Change" in December to cooperate regionally on solving energy problems.  


The Washington "Clean Air, Clean Fuels" bill would make $20 million available for a 25 percent cut in petroleum use by state vehicle fleets by 2020, help school districts acquire new alternative-fuel buses, and fund biofuels research at Washington State University, among other green programs. Seattle-based Washington Biodiesel plans to break ground in the second quarter this year for a plant in Warden in eastern Washington to produce 35 million gallons a year of biodiesel fuel using canola seed as the feedstock.


The plant is expected to begin production by the end of the first quarter of 2008. Washington Biodiesel has an agreement with the CHS-Cenex agricultural cooperative to supply canola and distribute biodiesel fuel. Imperium Renewables, another Washington company, is building a 100 million-gallons-a-year biodiesel plant at the Port of Grays Harbor on the Pacific Coast.


Acciona and Suncor Energy begin Ontario wind power project


January 30, 2007. Acciona Wind Energy Canada Inc. and Suncor Energy Products Inc. have started full-scale construction on their 76 MW wind power project near Ripley, Ontario. The Ontario Energy Board recently granted regulatory approval for the wind farm's two substations and transmission line, completing the project's key regulatory requirements.


The Ripley Wind Power Project will include 38 two-MW Enercon wind turbines, a transmission line and two electrical substations. The wind farm is located on the eastern shores of Lake Huron in Huron-Kinloss Township, approximately 220 kilometres west of Toronto and 140 kilometres north of London. The project is expected to have the capacity to generate enough zero-emission electricity to power 24,000 homes and offset approximately 66,000 tonnes of carbon dioxide annually. Project cost is estimated at approximately $176 mn (Rs 7.75 bn). Construction is expected to be complete this summer, with wind farm commissioning anticipated for late 2007.


The project is the result of the Ontario government's request for proposals to supply approximately 1,000 MW of renewable energy. The Ontario government aims to produce 10 per cent of the province's electricity from renewable sources by 2010. Suncor and Acciona will also submit an application for funding from the Canadian government's recently announced ecoEnergy Renewable Power Initiative, which supports wind power development in Canada. Suncor and Acciona are equal partners in the Ripley Wind Power Project.


They also jointly own and operate, along with Enbridge Inc., the 30-MW Magrath Wind Power Project and the 30-MW Chin Chute Wind Power Project, both in southern Alberta. Suncor and Enbridge own and operate the 11.2-MW SunBridge Wind Power Project near Gull Lake, Saskatchewan. Suncor, which operates a Sarnia-based refinery and a network of Sunoco retail stations, is also supporting renewable energy in Ontario through a $120-mn ($5.28 bn) ethanol plant in the Sarnia-Lambton region.


The St. Clair Ethanol Plant produces about 200 million litres of ethanol annually from approximately 20 million bushels of corn, making it the largest ethanol production facility in Canada. Since 1996, Suncor has been blending ethanol into its Sunoco gasolines. Ethanol-blended gasolines help reduce carbon monoxide emissions by up to 30 per cent.


Coconut oil to power plant


January 30, 2007. Coconut oil is set to make its mark at a bigger scale as the PNG Sustainable Energy Limited plans on a new bio-diesel standby generator for the Ramu nickel project. PNGSEL sealed another deal with the Madang Provincial Government that will enable them to participate in the construction of a standby power plant for the multi-billion kina Ramu project.


There were a lot of coconuts in the north coast area of Madang Province in Papua New Guinea and the aim was to reduce the cost running the power plant. The agreement would also boost the involvement of landowners in the development project and also provide a good impetus for the provision of power supply in the whole province. If the bio-diesel power plant was successful in Madang, then it should be considered for other parts of the country with large mining projects. The business arm of the MPG, the Madang Development Corporation will be working closely with PNGSEL to construct the standby power plant.


Appalachian native plans wind power for coalfields


January 27, 2007. Deep in corner of Appalachia, Genesis Development of Kentucky LLC is looking to wind as the next way to power its native coalfields. The company is evaluating several sites in eastern Kentucky to find a home for a wind farm, in hopes of delivering electricity to roughly 65,000 homes within the next five years. It's a risky endeavor, especially in a region known for its rugged terrain and reliance on coal. After all, most states that have seen success in developing wind energy as a renewable resource sit west of the Mississippi River, where the land is flatter and exposed to consistent winds. Kentucky has some potential for developing wind energy and that potential lies in eastern Kentucky. But there are no commercial or utility wind farms so far in the state.


Meanwhile, a few other Appalachian states have made strides in attracting wind-power developers. Pennsylvania has six commercial wind farms operating and another in the works, and West Virginia has one running and two proposed. Maryland's Public Service Commission approved two western Maryland wind farms in 2003 and is considering a third, though none have been built. Most of these projects are along the Allegheny Front, an Appalachian mountain ridge that includes the Eastern Continental Divide. Strong, relatively steady winds at elevations approaching 5,000 feet make the Allegheny Front attractive to wind-power developers.


The problem for most of Kentucky is that the vast majority of the state sits outside of the front, faring poorly in federal studies tracking wind speed and consistency. Bush pointed to a map by the Department of Energy that classifies the strength of wind power, on a scale of 1 to 7, across different states and regions within the United States. The study classified most of Kentucky as a 1, meaning it had little to no wind power. Southeastern Kentucky received a 2, and a thin area bordering Virginia (along the Allegheny Front) fared better with a 3. The overall DOE assessment indicated that Kentucky would be a poor place to set up wind farms and no further government studies on its wind power were conducted. The top five states for wind energy are North Dakota, Texas, Kansas, South Dakota and Montana, respectively, according to the American Wind Energy Association. Bush said developers in Kentucky are pursuing other types of renewable energy, such as agricultural waste, or biomass, and hydropower, which are abundant in the state. Coal-to-liquid technology is also attracting investors. Since wind energy has the least potential, the state has no plans to offer incentives for developing it.


Nationally, renewable sources of energy make up only 10 percent of the electric sector, according to the Energy Information Administration. Hydropower makes up 75 percent of that contribution, while wind is 9 percent. Coal remains an energy leader, supplying 53 percent of the nation's electricity. Genesis Development of Kentucky LLC goal is to set up a wind farm with about 40-50 turbines within the next five years, generating 100 MW of energy to serve 65,000 homes.


Dania plans to install 124 solar-powered streetlights


January 26 2007. The city is spending about $1 mn (Rs 44 mn) on a solar-powered streetlight project designed to help reduce its dependence on electricity. City will open bids on the project, which calls for 124 solar-powered fixtures and concrete poles. Dania has plans for an additional 75 solar-powered streetlights. If successful, the program could be expanded and save taxpayers a lot of money. Dania's solar energy project is being funded through a grant from the U.S. Department of Housing and Urban Development. The project, expected to be completed within four months, is among infrastructure improvements requested by residents of the area, which the city annexed in 2001. The city decided to launch the solar program after FPL couldn't quickly restore power and repair damaged poles following Hurricane Wilma in October 2005.

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