MonitorsPublished on Oct 30, 2006
Energy News Monitor I Volume III, Issue 19
ORF Exclusive directly from USA Energy Policy: Is there anything new?

The first energy shock that brought energy policy to the fore in America was triggered by coal and not by oil as is commonly believed.  Coal accounted for nearly 75 percent of energy consumed in America in 1917.  The demands of World War I, shortage of mining labour and railroad tie-ups led to a severe coal shortage that doubled coal prices within a short span of a month.  Among policies adopted in 1917 were coal allocation procedures, curtailment of non-essential use, conservation measures including fuel adjustment on consumer electricity bills, the extension of daylight-savings time and lowering of thermostat settings to 20 C. 

The second energy shock in America followed in 1919 when coal minors went on strike and virtually shut down coal production.  This shock proved to be a blessing as it introduced flexibility in the American energy system bringing in oil and gas as viable alternatives to coal. Oil, which was discovered in the late 1890s, had already begun to replace whale oil in illuminating residential and commercial sectors.  More significantly, oil had established its credibility as a versatile and efficient energy source for transportation through Word War I.  

The energy density, transportability and storage advantages of oil over coal propelled oil to the number one spot in just a few decades. Per capita consumption of petroleum increased virtually without interruption in America from half a barrel per person annually in 1900 to seventeen barrels per person annually in 1950. As oil began to replace coal in different sectors, particularly transportation, demand for oil grew faster than anticipated, and America became a net importer of oil briefly between 1920 and 1922.  While that trend was quickly reversed, a complete shift in the foreign trade position of America, from that of the largest net exporter of oil to that of the largest net importer occurred during the late 1940's in a period during which America continued to produce more than one-half of the world's crude oil.  From then on controlling import of oil became an object of U.S. government policy. 

Consensus among experts was that America should rely on coal for continuing its industrial development, as it did not possess enough hydrocarbon resources.  This view reflected the state of knowledge about the availability of resources at that time. At the beginning of the century and for many years thereafter, oil resources were so grossly underestimated that their exhaustion was expected in the near future; hence it was thought that oil could be disregarded in any long-range projections of energy use. 

Following the termination of price controls in America in July 1946, oil prices soared to levels unseen in three decades.  The posted price of West Texas Intermediate (WTI) grade crude which was frozen at $ 0.92 per bbl during the war, increased to $ 1.27 by the end of July 1946 and subsequently increased to $ 2.32 by December 1947. Despite peak domestic production, America became a net importer of oil in 1948.  By 1950, net imports of oil were approaching 10 percent of demand.  Senators from coal and oil producing states used the highly persuasive argument of national security and the need to protect the domestic industry to push for limits on imported oil.  It was probably in this period that the ‘energy problem’ began to appear in the guise of an ‘import problem’ and ever since remained a target for action of energy policies. The most stringent measure to control imported oil was enacted by the Eisenhower administration in 1959 with the Mandatory Oil Import Control Programme that imposed quota allocations to limit imports to less than 12-15 percent of demand. 

India appears to have used the short cut of borrowing this line of thought to help its own understanding of the yet to be fully understood idea of ‘energy security’.  Much of the writing on India’s energy security talks about the problem of oil import dependence, about the need to develop alternatives and about the need to conserve.  There is nothing inherently wrong in these suggestions, but the fact that we are just borrowing ideas rather than studying our own unique needs seen in the context of new global realities, is troubling. These policies were made in America during the cold war era, when hostility dominated perceptions of nations.  One can also see recommendations that India should pursue the unrealistic ideal of achieving energy independence, again taken from the garbage bin of American policy. 

When the Arab Oil embargo hit the world in 1973, America had no Department of Energy in the executive branch and no Committee on Energy in either houses of the congress. There was no knowledge or understanding of the issue within the American Government. ‘Project Independence’ was in fact an ill defined idea that bore no relation to economic or technical realities but circulated by the Nixon administration to buy time before the government could come up with a credible response to the oil shock. The propaganda was that ‘Project independence’ would allow America to produce (drill wherever possible), conserve and innovate its way out of the import problem.  Very soon the budget office realised that energy independence would mean using substitutes which were much more expensive than OPEC oil.

Import levels of oil are not a measure of the success, failure or absence of energy policy as it is made out to be.  It is the result of energy policy that trusts the market to deliver energy whenever and wherever it is required and demands a price for it.  What matters is our ability to pay that price. Energy policies are derivative policies that reflect higher-level policy goals.  These higher-level policy goals perceived in the cold war era are not the same as those of today.  Many threats perceived by the cold war era no longer exist.  

Indian energy policy must move away from worn out rhetoric and focus on today’s realities that call for equity in sharing resources and accountability in using resources.

Can Nuclear Power Solve the Global Warming Problem? (Part – II)

By Brice Smith

(Continued from Issue – 17)

Proposals to reprocess the spent fuel would not only not solve the waste problem, but would greatly increase the dangers. Reprocessing schemes are expensive and create a number of serious environmental risks while still generating large volumes of waste destined for repository disposal. In addition, reprocessing results in the separation of weapons-useable plutonium, adding significantly to the risks of proliferation. While future reprocessing technologies like UREX+ or pyroprocessing could have some nonproliferation benefits, they would still pose a significant risk if deployed on a large scale. Under the global growth scenario, the authors of the MIT study estimate that more than 155 metric tons of separated plutonium would be required annually to supply the required MOX (mixed-oxide) fuel.

Just one percent of this commercial plutonium would be sufficient to produce more than 190 nuclear weapons every year. The authors of the MIT study acknowledge the high cost and negative impacts of reprocessing and, as such, advocate against its use. Instead they propose interim storage and expanded research on deep borehole disposal. It is possible that deep boreholes might prove to be an alternative in countries with smaller amounts of waste. However, committing to a large increase in the rate of waste generation based only on the potential plausibility of a future waste management option would be to repeat the central error of nuclear power’s past. The concept for mined geologic repositories dates back to at least 1957. However, turning this idea into a reality has proven quite difficult, and not one spent fuel rod has yet been permanently disposed of anywhere in the world.


Nuclear power is likely to be an expensive source of electricity, with projected costs in the range of six to seven cents per kilowatt-hour (kWh) for new reactors. Tables 1 and 2 show data from the MIT study and a study conducted at the University of Chicago. Table 1 shows estimates used for the projected capital costs, construction lead times and interest rate for natural gas, coal and nuclear power in the United States. Table 2 shows estimates of cost per kilowatt-hour.

Table 1: Comparison of some assumptions used in the MIT and University of Chicago Studies


MIT Study (2003)

University of


Study (2004)





 ($ per









 ($ per









Natural Gas




500 to 700







1182 to 1430







1200 to 1800



1: Overnight Capital Cost     2:Lead Time for Construction3: Effective Interest Rate   4: Overnight Capital Cost5: Lead Time for Construction6: Effective Interest Rate

Table 2: Levelized cost of electricity estimated by the MIT and University of Chicago Studies



MIT Study (2003)


University of Chicago Study (2004)


4.2 cents per kWh

3.3 to 4.1 cents per kWh

Natural Gasb

3.8 to 5.6 cents per kWh

3.5 to 4.5 cents per kWh

Nuclear Powerc

6.7 cents per kWh

6.2 cents per kWh

(a) These estimates are for pulverized coal fired plants. Levelized cost of coal in the MIT study is $1.30 per million Btu (MMBtu) while the average price of coal in the U Chicago study is $1.02 to $1.23 per MMBtu.

(b) These estimates are for combined cycle gas technology (CCGT) natural gas plants. Levelized cost of natural gas in the MIT study is $3.77 to $6.72 per MMBtu. The average price of natural gas in the U Chicago study is $3.39 to $4.46 per MMBtu. The recent price for natural gas has been well above the “high” fuel price used in these studies. However, long-term gas prices can be expected to remain within the range of costs assumed by the MIT study if policies on efficiency, conservation, and an increased reliance on liquefied natural gas are pursued.

(c) Overnight capital cost of a nuclear plant in the MIT study is $2,000 per kW. While the U Chicago analysis considered a range of capital costs from $1,200 to $1,800 per kW, the lower end of this range was so far out of what could be reasonably expected from experience in the United States and around the world that it is not a credible basis for analysis. The middle of the U Chicago range, $1,500 per kW, was used in this analysis.

While a number of potential cost reductions have been considered by nuclear power proponents in the United States, it is unlikely that plants not heavily subsidized by the federal government would be able to achieve these. This is particularly true given that the cost improvements would have to be maintained under the very demanding timetables set by the global or steady-state growth scenario.

Promising alternatives

A number of energy alternatives that are economically competitive with new nuclear power are available in the near to medium term. The choice between these alternatives will hinge primarily on the rapidity with which they can be brought online and on their relative environmental and security impacts.

Of the available near-term options for reducing greenhouse gas emissions, the two most promising ones in the United States and other areas of the Global North are increasing efficiency and expanding the use of wind power at favorable sites. At approximately four to six cents per kWh, wind power at favorable sites in the United States is already competitive with natural gas or new nuclear power. With the proper priorities on upgrading the transmission and distribution infrastructure and changing the way the electricity sector is regulated, wind power could expand rapidly in the United States. In fact, without any major changes to the existing grid, wind power could expand to 15 to 20 percent of U.S. electricity supply, as compared to less than one-half of one percent in 2003, without negatively impacting overall stability or reliability.

Improvements in energy efficiency could continue to be made in the medium term as well. For example, as the current building stock turns over, older buildings could be replaced by more efficient designs. In addition, the utilization of wind power, thin-film solar cells, advanced hydropower at existing dams, and some types of sustainable biomass could allow renewables to make up an increasingly significant proportion of the electricity supply over the medium term. This expansion of renewables could be facilitated through the development of a robust mix of technologies, the development of strengthened regional grids to help stabilize the contribution of wind and solar power through geographic distribution, the use of pumped hydropower systems to store excess electricity during times of low demand, and the tighter integration of large scale wind farms with natural gas fired capacity.

While it would require a significant effort to implement new efficiency programs and to develop the necessary infrastructure to expand wind power, these efforts must be compared to the difficulties that would be encountered in restarting a nuclear power industry that hasn’t had a new order placed in the United States in more than 25 years and hasn’t opened a single new plant in the last ten years. In addition, the current fossil fuel based energy system is very expensive to maintain. For example, the International Energy Agency estimates that the amount of investment in oil and gas between 2001 and 2030 will total nearly $6.1 trillion, with 72 percent of that going towards new exploration and development efforts.

Transition technologies

Energy efficiency and renewable energy programs have few negative environmental or security impacts compared to our present energy system and, in fact, have many advantages. As a result, these options should be pursued to the maximum extent possible. However, in order to stabilize the climate, it appears likely that some energy sources with more significant tradeoffs will also be needed as transition technologies. The two most important transition strategies are increased reliance on the import of liquefied natural gas (LNG) and the development of integrated coal gasification plants (IGCC — integrated gasification combined cycle) with sequestration of the carbon dioxide emissions in geologic formations. Compared to pulverized coal plants, combined cycle natural gas plants emit about 55 percent less CO2 for the same amount of generation. If efficiency improvements and an expanded liquidification and regasification infrastructure can stabilize the long-term price of natural gas at the cost of imported LNG, then the use of combined cycle natural gas plants is likely to remain an economically viable choice for replacing highly inefficient coal fired plants. The use of coal gasification technologies would greatly reduce the emissions of mercury, particulates, and sulfur and nitrogen oxides from the burning of coal. However, for coal gasification to be considered as a potentially viable transition technology, it must be accompanied by carbon sequestration, the injection and storage of CO2 into geologic formations. Experience in the United States with carbon dioxide injection as part of enhanced oil recovery has been gained since at least 1972. In addition, the feasibility of sequestering carbon dioxide has been demonstrated at both the Sleipner gas fields in the North Sea and the In Salah natural gas fields in Algeria. While the costs of such strategies are more uncertain than those of other mitigation options, estimates for the cost of electricity from power plants with carbon sequestration still fall within the range of six to seven cents per kWh. Some of the most troubling aspects of coal, such as mountain top removal mining, would be mitigated by the reduction in demand due to increased efficiency and the rapid expansion of alternative energy sources. In addition, it appears likely that coal gasification and carbon sequestration would be better suited to the Western United States given the greater access to oil and gas fields which have already been explored and which offer the potential for added economic benefits from enhanced oil and gas recovery. On the other hand, the Eastern United States would appear better suited for an expanded use of LNG during the transition given the existing regasification capacity, the well-developed distribution system, and the shorter transportation routes from the Caribbean, Venezuela, and Western Africa. The continued use of fossil fuels during the transition period will have many serious drawbacks. However, these must be weighed against the potentially catastrophic damage that could result from global warming and against the unique dangers that accompany the use of nuclear power. To trade one uncertain but potentially catastrophic health, environmental and security threat for another is not a sensible basis for an energy policy.

No energy system is free of negative impacts. The challenge is to choose the least bad mix of options in the near to medium term while achieving significant global reductions in CO2 emissions, and to move long term toward the development of a sustainable and equitable global energy system.


Just as the claim by Atomic Energy Commission Chairman Lewis Strauss that nuclear power would one day be “too cheap to meter” was known to be a myth well before ground was broken on the first civilian reactor in the United States, and just as the link between the nuclear fuel cycle and the potential to manufacture nuclear weapons was widely acknowledged before President Eisenhower first voiced his vision for the “Atoms-for-Peace” program, a careful examination today reveals that the expense and vulnerabilities associated with nuclear power would make it a risky and unsustainable option for reducing greenhouse gas emissions. As the authors of the MIT report themselves conclude:

The potential impact on the public from safety or waste management failure and the link to nuclear explosives technology are unique to nuclear energy among energy supply options. These characteristics and the fact that nuclear is more costly, make it impossible today to make a credible case for the immediate expanded use of nuclear power.

Nuclear power is a uniquely dangerous source of electricity that would create a number of serious risks if employed on a large scale. It is very unlikely that the problems with nuclear power could be successfully overcome given the large number of reactors required for even modestly affecting carbon dioxide emissions. It has now been more than 50 years since the birth of the civilian nuclear industry and more than 25 years since the last reactor order was placed in the United States. It is time to move on from considering the nuclear option and to begin focusing on developing more rapid, robust and sustainable options for addressing the most pressing environmental concern of our day. The alternatives are available if the public and their decision makers have the will to make them a reality. If not, our children and grandchildren will have to live with the consequences.

Courtesy: Science for Democratic Action (Volume 14, Number 2), published by Institute for Energy and Environmental Research.


Public’s Opposition to Electricity Tariff Increase (Part – II)

Shankar Sharma

[email protected]

(Continued from Issue – 17)

¨        The initiative as taken in Maharastra to supply the energy efficient Compact Fluorescent Lamps (CFL) to the consumers to replace the huge number of inefficient incandescent lamps will result in immediate savings.

¨        “MSEDCL had distributed close to four lakh CFL bulbs at Nashik at a fat discount to be recovered over 10 installments. Now, it plans to save about 900 MW during the morning and evening peak hours by large scale use of the energy-efficient CFL bulbs” as per a news item.

¨        Reliance Energy has entered into exclusive tie-up with Bajaj Electricals to distribute compact fluorescent light bulbs to its 2.5 million customers in Mumbai and adjoining areas, which will reduce consumption of power in REL distribution area by at least 2.5 lakh units per month.

¨        At a price of about Rs. 150/- the usage of a 10 Watt CFL can mean 50 Watt saving (compared to a 60 W incandescent lamp) which translates to about Rs. 3 per watt or Rs. 0.3 crores per Negawatt. This is nearly one fifteenth of the amount required to set up 1 MW of generating capacity.

¨        Even if we take into account the replacement of CFL once in three years and the decrease in PF, a conservative estimate shows that the reduction in demand can be achieved at less than Rs. 1 Crore per MW, as compared to 5 to 6 MW of new generation capacity.

¨        If the cost of CFL is passed on to the consumers, as it should, the savings will be much more.

¨        This will be in addition to the fossil fuel saving throughout, and the attendant environmental costs, T&D losses etc.

¨        The peak demand and annual energy reduction by effective implementation of this DSM measure will be huge. Out of 130 lakh installations in the state requiring illumination, assuming an average of 4 bulbs per installation, the saving by replacing 50% of these installations could be about 2,000 MU per year and a peak demand saving of about 1,200 MW.

¨        This option should be taken up urgently as the gestation period is almost zero.

¨        Usage of electricity for water heating can be termed as the most inefficient use of electricity. The approximate number of AEH consumers in Karnataka, is about 14 lakhs. Even if 75% of these AEH consumers can be encouraged to install solar panels for water heating, a conservatively estimated 900 MW of morning peak demand, about 200 MW of evening peak demand, and about 1,200 MU of energy per year could be saved.

¨        This technology should also be made popular in hotels, restaurants, canteens, hospitals and other places needing hot water on a regular basis.

¨        The investment needed for this implementation by ESCOMs will be negligible as compared to the benefits of saving the huge cost of peak demand power.  To make this option attractive throughout the state the max. discount admissible now should be increased to about Rs. 100, and can be stopped after about 5 years.

¨        In addition Solar PV panels for lighting should be encouraged at least in remote rural areas where providing the grid quality power will be uneconomical. 

¨        Solar PV panels for street lighting and traffic signaling are two other areas worth seriously considering. 

¨        Adequate investment through KREDL in making the combination of combined solar and wind power more efficient and less costly should be given a serious consideration.

¨        Improving the efficiency of IP sets can result in savings of about 30% of the energy sold in the state. Since the revenue return from these IP sets is very small at present, the investment to make them energy efficient will be a huge benefit to the entire society.

¨        Adequate investment in this area spread over 5 years can release about 30% of the stored energy for economical uses, and reduce the energy requirement by 30%.

¨        This opportunity can also be used to persuade the beneficiaries to fix the energy meters. These efforts will also reduce the transformer failures.

¨        Solar water pumps for smaller requirements are another area requiring serious attention. With about 330 days of adequate sunlight, most parts of the state can make use of solar power for water pumping.

¨        Adequate investment through KREDL in JV with private manufacturers can lead to massive benefits to the society as a whole, in addition to reducing the demand for electricity.

¨        Distributed energy sources like Solar PV panels, solar water heaters, wind mills etc should be viewed as good opportunity to reduce the demand on the grid.

¨        The cost of these sources will keep coming down with increased efficiency and wider use, whereas the cost of energy from the conventional sources like coal or dam based hydro power projects will keep increasing.

¨        The important issue for ESCOMs is the state will experience increased opposition to large power projects like coal power or dam based power, as seen in the cases of Tadadi, Nandikur or Gondiya hydel project proposals.  Hence supply side augmentation through large projects will not be easy.

¨        Energy conservation potential, as per National Productivity Council and Planning Commission in industrial, commercial and domestic sectors is estimated to be about 25% of the energy consumed at present in those sectors. So there is a huge potential.

¨        Compulsory energy auditing to all consumers of connected load above certain level, say 25 kW, can go a long way in reducing the demand, and conserving energy.

¨        Suitable but stiff tariff for non-essential uses like decorative lighting, temporary connections, night time sports etc. should be enforced to discourage wastage.

¨        So, DSM and energy conservation should be an essential part of the operational strategy.

Paradigm shift

Effective DSM is crucial for the operational viability of the ESCOMs, to preserve our environment, and ensure energy security on a sustainable basis.  In this regard paradigm shift is needed for the entire society.

¨        The power scenario for the state in 2005-06 indicates that there was only 0.75 % energy shortage, but 10% peak demand shortage.

¨        A combination of one or more of the above mentioned DSM measures can certainly bring down the peak demand, and reduce the energy requirement such that there need not be any deficit for the foreseeable future.

¨        Against this feasibility the state is planning for additional coal and gas fired power stations to meet the peak demand in a state having any known reserve of fossil fuels.

¨        The social and environmental impact of coal, gas or dam based power stations is well known, because of which popular opposition is getting louder.

¨        In a paper titeld “Generation Planning Principles – A Short Note on Karnataka,” D. Narasimha Rao, Visiting Faculty, IIM Bangalore, is understood to have shown that all capacity plans, budget submissions, and five-year plans speak of peak shortages, yet respond by planning for base load capacity.

¨        It also says that if all the proposed capacity as planned today is to be built, by FY2015 a good portion of it would sit idle for a lot of the time. The simulation shows that the projected coal and gas plants, if all built, would run at a combined average PLF of 22-24% in FY11 and 39-42% in FY15, depending on hydro conditions.

¨        This scenario can be nothing short of sacrilege of the natural resources, because of the huge but unnecessary costs to the society.

¨        Some calculations indicate that even with 5% CAGR for Karnataka, the projected demand of the state in 2016, can be reduced to approximately today’s level by a combination of efficiency improvement, DSM measures plus deployment of solar technology for some applications.

¨        What it basically means is the unscientific way the authorities are proceeding with the planning and addition of large size power projects are not necessary, and if not reviewed carefully they may result in excess of base load capacity in few years. These projections are of huge significance, if considered seriously for future planning. 

¨        Against the total availability of 7,767.0 MW from various sources as at the beginning of this year, a peak demand of 6,160 MW could not be met fully, and a deficit of about 600 MW was reported in the year 2005-06.  The annual energy requirement was 34,800 MU and a deficit of only 251 MU was reported.  These figures represented 9.8% and 0.74 % in peak demand and annual energy deficits.

¨        As an accepted norm if we allow even 20% for forced outages and auxiliary consumption, a demand of 6,200 MW out of 7,767.0 MW of total available generation capacity could have been easily met.  In addition, if 10% technical losses are saved in the previous year, the actual demand could have been 5,600 MW. If the technical losses were to have been minimum at about 10%, the actual peak demand last year could have been less than 5,000 MW. This shows that the system is not adequately managed.

¨        It is also important to note that the effective demand side management and energy conservation measures could have avoided some of the peak load stations like Varahi, or costly Diesel Power Station at Yelahanka, or Rayalaseema, Tata, Jindal, Tannir Bhavi etc.

¨        The ESCOMs should also consider the feasibility of earning Carbon credit for deploying the DSM measures and Non-Conventional Energy (NCE) sources.

Part III - Prayer

In this regard, it would be prudent for the honorable Commission to summarily reject the tariff application of ESCOMs, and issue directive to ESCOMs to come up with fresh ERC after full compliance with the relevant provisions of Acts, earlier directives of the Commission and the following issues:

Directives for compliance immediately

ESCOMs should not approach the Commission for revision of tariff again without the full compliance of each of the following issues:

A1) Not less than 95% of all the installations should be fitted with adequate accuracy energy meters;

A2) 100% revenue collection efficiency should be reached for three consecutive years;

A3) Aggregate Technical and Commercial loss should fall below 10%;

A4) An effective customer satisfaction survey should reveal a satisfaction level >75%;

A5) Performance of operation as indicated by SAIFI, SAIDI and CAIDI should reach top 10 in the country;

A6) Voltage level at each of the DTCs shall be within the prescribed limits, and not less than 90% of the voltage readings taken at the far end of LT feeders across each taluk shall be within the prescribed limits;

A7) By adopting the action plan discussed in part II above, the ESCOMs should provide quality electricity supply to all the legitimate consumers in Karnataka without peak hour or energy shortage for three consecutive years;

A8) By effectively encouraging the consumers to adopt suitable non-conventional energy sources, the net demand for grid quality electricity should come down by a minimum of 3 % in three consecutive years;

A9) Improve the operational and commercial performance so as to balance the average cost of supply and revenue for three consecutive years, with or without subsidy from the state govt.;

A10) Reduce the cost of subsidy by the state govt. below 50% of what was received in the financial year 2005-06.

 A11) Ensure that the assets are valued adequately and insured accordingly; the insurance level should be adequate for its staff and consumers also.

A12) The present method of sending the reply to objectors by ESCOMS is unsatisfactory: each of the issues raised by the objectors should be addressed adequately; also major issues should be discussed at the Company level.

A13) Undertake scientific study of determining the cost of service to each category of consumers, and propose suitable tariff eliminating cross subsidies, so as to discourage wastage and promote high level of efficiency in usage of electricity.

Recommendations for further improvement

Further, the Commission should advise ESCOMs to demonstrate at the time of next filing of tariff revision application that honest attempts have been made to adhere to the following recommendations:

B1) World best work practices in planning, design, construction, specification, procurement, testing, commissioning, operation, maintenance, fault investigation, repair procedures, safety aspects, cost control, records; and the performance/service standards are adopted;

B2) Regular peer review of work practices is undertaken;

B3) Benchmarking of all the major performance parameters at international levels be undertaken;

B4) Target to procure 25% of the electrical energy from non-conventional energy sources by year 2015.

B5) Target to reduce the demand for grid quality electricity in year 2016 to the present level by improving the efficiency of the network, DSM, energy conservation, and effectively encouraging the non-conventional energy sources.

B6) Target to eliminate the need for fossil fuel power stations in the state by 2020 by entering into long term power purchase agreement with energy rich states or private companies in energy rich states.

B7) Target to achieve 100% revenue collection by each ESCOM on a regular basis.

B8) Target to reduce the electrical accidents by 2010 to less than 5% of that in 2004-05.

B9) Target to achieve the customer satisfaction of above 90% by 2010.

B10) Target to eliminate the need for govt. subsidy completely by 2010.

B11) ESCOMs should be asked to submit business plan for next 3 -5 years along with targets for reducing the losses and increase in revenue collection and % of metering.

Additional Prayer:

The formation of Electricity Regulatory Commissions has been one of the best things to happen to the electricity industry in recent years. Electricity Regulatory Commissions have the potential to set right various anomalies facing the electricity industry, and the public is reposing a lot of hope on this potential.

¨        Unless the Society and the honorable Commission itself take the necessary precautions, there is a credible risk of ESCOMs undermining the role of KERC by repeatedly failing to conform to various directives.

¨        The ESCOMs also give an impression to the public that they do not attach any importance to the views of the public by refusing to provide satisfactory response to various objections or suggestions made.

IE Act 2003

Section 61 (G) says: The Appropriate Commission ……….. shall be guided by the following, namely: “that the tariff progressively reflects the cost of supply of electricity, and also reduces and eliminates cross-subsidies within the period to be specified by the Appropriate Commission”.

The honorable Commission may deliberate on this requirement of the Act and specify at an early date, the period within which cross-subsidies will be eliminated.  Without such specification the ESCOMs will have no incentive to work towards the objective.


National Electricity Policy

Clause 8.3 (3): Implies that while fixing tariff for IP sets at a rate less than that of the actual cost of supply, it is imperative for the Commission to keep in mind the need for use of ground water resources in a sustainable manner.

Clause 8.3 (4): Implies that the policy should also take into account the fact that the subsidized electricity to IP sets can result in the lowering of water table in some geographical areas. Subsidised rate for energy supply for IP sets of such areas should be at a pre-determined rate of energy consumption, beyond which the actual cost of supply should be charged.

¨        The fast depletion of ground water is a very serious issue for the whole society. 

¨        Whereas there is continuous increase in highly subsidized IP set energy consumption resulting in over exploitation of ground water, there is no clear indication of a corresponding increase in food production. 

¨        Detailed studies regarding the phenomenon of ground water depletion, comprehensive survey of different areas, and fixing the appropriate rate of energy consumption per month under subsidized supply regime should be done early.

¨        The Commission may like to consider a recent decision of the Andhra Pradesh govt. to replace all the old and inefficient IP sets by new efficient IP sets, and make similar recommendation to the Karnataka state govt.

¨        In view of the continued failure of the ESCOMs to meet the increasing demand for electricity, the Commission may also like to deliberate on all the related issues and to make recommendations to the state govt. to invest in DSM and making the distributed generation sources of non-conventional energy much more popular.  

¨        The impact of the electricity industry on the society is huge, because of which its efficient and responsible functioning is of paramount importance.  The Commission should not allow the ESCOMs to continue ‘the business as usual’, and should not hesitate to take a pragmatic approach and issue far reaching directives to ESCOMs.

Views are personal







OVL to get 2.4 mt from Sakhalin - I

October 23, 2006. India's share of crude oil from the Sakhalin-I project offshore eastern Russia will reach 2.4 million tonnes in 2007 and then decline for the next five years. Oil output from the Sakhalin-I project, where ONGC Videsh Ltd has 20 per cent stake, is likely to yo-yo partly because of the project consortium, led by ExxonMobil, has failed to agree with Russian authorities on extending its license area to the north. Sakhalin-I project will reach the peak rate of 12 million tonnes per year once a new onshore crude processing unit is commissioned in December. OVL's share will be 20 per cent.

Output from the Chayyo field being developed by the Sakhalin-I partners, will fall to 9 million tonnes in 2012, rise back to 12.5 million tonnes in 2014 and then decline once more after 2017 to as little as 6 million tonnes per year in 2023. The consortium was looking at commissioning the Odoptu field as well as Arkutun-Dagi field ahead of schedule to maintain the production. The current schedule provides for the Odoptu and Arkutun-Dagi fields to be put on line in 2009 and 2015, respectively.

Sakhalin oil may reach Indian shores on Nov

October 23, 2006. The first shipment of equity oil from Russian oilfield Sakhalin-I is expected to touch the Indian coast on November 20. ONGC’s $2.8bn in the Sakhalin project is the biggest investment so far in an overseas venture. With this, India is set to mark yet another milestone in its energy diversity as the first equity oil from Russia comes to the Mangalore Refinery. MRPL had also received earlier on the first cargo of equity crude from Sudan, the Greater Nile project.

ONGC is planning to develop MRPL as its petrochemical hub which will be a part of a special economic zone hosting an LNG complex, a refinery and a new petrochemical plant. ONGC Videsh (OVL), a foreign investment arm of ONGC, has projected to bring about 1,400,000 bbls of crude in two cargoes from the Sakhalin-I project to India by December ’06. OVL has a 20% stake in the project. Sakhalin-I has three fields — Chayvo, Odoptu, and Arkutun Dagi. Production of crude in these fields will be undertaken in phases. Ultimately, 34 wells are planned to be drilled from sites during phase-I of the Sakhalin-I project development.

The first shipment of crude from Sakhalin-I will come to India in November this year. Other equity partners in the venture are Exxon Neftegas (30%), Japan’s Sakhalin Oil & Gas Development (30%), SMNG-S (11.5%), and RN Astra (8.5%). Exxon Mobil’s affiliate Exxon-N is the operator of the project. While part of the crude would be refined at ONGC’s subsidiary MRPL, part of it could be auctioned. The crude is stated to be high-quality low-sulphur crude and ONGC is interested to refine it through its refining arm.

The Sakhalin-I field is likely to produce about 12.5m tonnes of oil and 10bn cubic meter of gas annually at the peak of production. OVL would have a 20% stake in it. It is estimated that the total production of Sakhalin-I in its 40-year life span is around 306m tonnes of oil and 485bn cubic meter of gas. Earlier, India has received 1,407,000 tonnes of equity oil from OVL’s Sudan property.


IOC ups heavy crude oil capacity

October 23, 2006. To push up its gross refining margins, Indian Oil Corporation (IOC) is planning to invest around Rs 12,000 crore to upgrade its refining facilities to handle high sulphur crude oil. By 2010, the company will upgrade five of its refineries at Mathura, Panipat, Barauni, Koyali and Haldia, enhancing the heavy crude oil, or high sulphur crude oil, handling capacity to 66.85 million tonnes per annum (mmtpa). These capacities will be in addition to the 12 mmtpa, scaleable to 15 mmtpa, coming up at Paradip, which will handle 100 per cent heavy crude oil. The Paradip refinery is also expected to come up by 2010. Currently, IOC has a heavy crude oil handling capacity of 14.9 mmtpa, 30 per cent of its total capacity.  

The plan is expected to push up the company’s refining margins to $10 a barrel. Overall, refining margins had declined to $4.6 a barrel in 2005-06, from $ 6.21 in 2004-05. This year, the gross refining margins stood at $6 a barrel for the quarter ended June 30.  The refinery-wise plan includes setting up a residue upgrade plant at the Koyali refinery near Baroda in Gujarat, which will also enable the plant to absorb the indigenous Gujarat crude oil output — 2.3 mmtpa from south Gujarat and 3.5 mmtpa from north Gujarat. The proposed investment is pegged at Rs 3,940 crore. 

 At Barauni, the company is setting up a heavy crude oil maximisation project with a high sulphur processing coker revamp at a cost of Rs 790 crore.  For the Panipat refinery, a crude oil blending plant and a storage facility are being set up at Mundra port for pumping crude oil through the Mundra-Panipat crude oil pipeline at a cost of Rs 1,011 crore. Work on expanding the refining capacity to 15 mmtpa is already on. This will have an investment of Rs 4,165 crore. 

At Haldia, IOC is setting up a hydro cracker unit to improve yield and distillate quality at a cost of Rs 1,876 crore.  At Mathura, IOC is considering enhancing the heavy crude oil processing capacity to 65 per cent from 57 per cent and setting up a diesel quality improvement project. An additional sulphur recovery unit is also expected to come up, along with an upgrade of the bitumen technology. 

Once the 100 per cent heavy crude oil refining capacity comes up at Paradip, up to 73 per cent of IOC’s refining capacities will be dedicated to heavy crude oil. This will also increase the total high sulphur crude oil throughput to 49 mmtpa, which is 87 per cent of the company’s entire imports. IOC has been expanding its crude oil mix over the last three years. It now sources 58 different varieties of crude oil, compared with 23 three years ago. It plans to add another 15 varieties sourced from Libya, Colombia, Canada, Congo, Gabon, Venezuela, and Guinea. 

Reliance Petro spends $0.89bn on refinery project

October 19, 2006. Reliance Petroleum Ltd (RPL) has spent Rs 4,054.50 crore on its refinery under construction at Jamnagar against the projected Rs 7,266 crore. The company has tied up for long-term foreign currency borrowing of $2 billion on October 13 and expects to draw funds in the current quarter. The balance of the money raised through the IPO is being held as cash and bank balance at Rs 4851.21 crore, deposits Rs 1,100 crore, and current investment Rs 3,459.05 crore. The basic engineering work on the project has been completed. Nearly 75 per cent of the procurement commitments and contracts have been finalized. The project is to be commissioned by December 2008.

IOC plans $6 bn refinery in Ceyhan of Turkey

October 17, 2006. Indian Oil is looking at Europe for growth. The country's largest refiner has applied to the Energy Market Regulatory Authority of Turkey for setting up a 15-million-tonne, $6-billion grassroots refinery at the Mediterranean port city, Ceyhan. Since Turkey has very low appetite for refined products, the project would primarily focus on exports to Europe. Other companies which expressed interest in setting up refinery in Ceyhan are Kazakh oil company KazmunaiGas and Turkish Petrol Office.

In a parallel development, the company is negotiating with a consortium of ENI, Italy and Calik Group of Turkey for a "significant" stake in the $1.5-billion oil pipeline from the Turkish Northern Black Sea city Samsun to Ceyhan. IOC entered into a MoU with Calik Group in 2005 to jointly explore investment opportunities in the downstream sector in Turkey.

The 550-km Samsun-Ceyhan pipeline will carry up to 1.5 million barrels of crude per day primarily from Kazakhstan and will replace the tanker movements through the Bosphorus straits by almost 50 per cent. Apart from IOC, Royal Dutch Shell has also expressed intention to take part in the project. IOC is exploring opportunities in the refining and pipeline sector in Turkey for last two years and was outbid by a Shell-led consortium in the race for majority stake in the Tupras Refinery, last year. Located between the oil rich land-locked CIS countries and the Black Sea and the Mediterranean, Turkey has already witnessed commissioning of 1,760-km-long world's second -longest Baku-Tbilisi-Ceyhan crude pipeline.

Transportation / Distribution / Trade

GAIL to expand CNG network to 46 cities

October 24, 2006. GAIL (India) Ltd is planning to expand its compressed natural gas (CNG) distribution network to 46 cities in the country over the next four years. At present, CNG, as a vehicle fuel, is available in Delhi, Mumbai, Agra, Kanpur and Lucknow. Cities like Ahmedabad, Chandigarh, Pune, Patna, Jodhpur, Hyderabad, Bangalore, Kolkata, Gwalior, Indore, Silchar, and Jaipur will soon be added to the list. GAIL believes its CNG network expansion plan will work on the premise that the cost of running a vehicle on CNG is almost one-third that of petrol. The automobile industry has been demanding expansion of the network for a long time to ensure integrated inter-city transport on CNG fuel.   

Absence of a proper CNG network has forced some auto companies to abandon it in favour of other alternative fuels. Market leader Maruti Udyog Ltd (MUL), which had launched CNG models earlier, has now opted for LPG due to its wider availability and convenient refuelling.  However, a few other companies are still banking on the cheaper CNG. Hyundai will soon launch Santro’s CNG model, while Ford Ikon’s CNG variant will be out in November. General Motors has already launched its premium sedan Optra on CNG. Ashok Leyland is launching CNG-run commercial vehicles early next year. 

Piped gas: IOC, RIL may form 50:50 joint venture

October 20, 2006. The city gas distribution joint venture project between IOC and Reliance Industries Ltd, which had got stuck on the issue of who would get to be majority partner, may finally move ahead. A new proposal envisaging equal ownership for both the partners is being considered now. Once the project structure is agreed upon, the two would enter into a general MoU, which would form the basis of the projects. The two companies would then set up a Steering Committee to identify the cities for setting up the distribution networks for piped natural gas to households and industries. The areas of co-operation include use of existing retail outlets for marketing CNG and LPG used by automobiles.

The original proposal envisaged 49 per cent equity for IOC. It also proposed that if any State Government expressed interest in a city gas distribution project, it would be given five per cent in such a way that combined strength of IOC and the State would not be more than 50 per cent. The joint venture was expected to leverage availability of gas from Reliance's huge find off the Andhra coast and IOC's extensive retail outlet network. IOC owns half of the 29,000 retail outlets run by PSUs.

Policy / Performance

PetroMin gives final touches to city gas policy

October 24, 2006. Petroleum ministry put final touches to the policy for laying natural gas pipelines and setting up city gas distribution networks with a view to protecting consumer interest and assuring adequate returns to investors. The Centre is likely to allow companies’ monopoly in retailing natural gas to households, and CNG to automobiles for a ‘limited period’, which would be decided on the basis of investment made, location and the market growth. Under the natural gas pipeline and city or local natural gas distribution networks policy, the exclusivity period for city gas distribution networks might vary between 3-5 years. The Ministry has held another round of consultations with stakeholders, including the Planning Commission and private firms like RIL and RNRL, on the policy.

Oil firms seek customs waiver on capital goods for new refineries

October 24, 2006. State-owned oil marketing companies are seeking zero customs duty for capital goods imported for the new refineries coming up in Punjab, Bina in Madhya Pradesh and Paradeep in Orissa.  The demand, part of the wishlist being prepared for the finance ministry for Budget 2007, is aimed at attaining a level playing field for the new refineries being set up. A similar incentive has been extended to private sector companies like Reliance Petroleum. 

At present, the rate of duty is 27.48 per cent. Among other demands, state-owned downstream companies like Hindustan Petroleum Corporation are seeking customs duty protection of at least 10 per cent between crude and petroleum products, duty relief on imported crude used for domestic cooking gas and PDS kerosene as well as concessional Customs duty for capital goods imported for green fuel and pipeline projects. 

The companies also want exemption of excise duty for captive consumption of petroleum products as fuel or otherwise, as well as the exemption for export to Nepal to be extended to all oil marketing companies. Another demand relates to cenvat credit on the Oil Industry Development Board cess on crude. On the income tax front, a demand for a tax holiday for cross country pipelines has been raised. The companies also want a tax holiday for new inland refineries from the year of making profits instead of the year of commercial production. 

Another issue being raised pertains to the 10.2 per cent service tax payable by goods transport agencies. While the SK Bhardwaj committee, constituted due to the transporters stir after the 2004 Budget, had specified conditions for making the levy applicable, a representation on the issue was disposed of by the CBEC upholding the liability despite the contradictions. 

Govt to take up seismic survey on gas hydrates

October 23, 2006. The Directorate General of Hydrocarbons (DGH) would undertake seismic survey for gas hydrates along the east and west coast of the country by early 2007. The 100 sq km survey would cost about $4 million. The new seismic survey is expected to provide the data about the extent and volume of gas hydrates in these offshore areas. The gas hydrates are ice-like crystalline compounds that occur naturally within 200-500 m below the seabed. The gas hydrates comprise pure form of methane gas and fresh water. In the exclusive economic zone of India, they are found at sea depth of more than 800 m. The DGH is conducting the exploration of gas hydrates under National Gas Hydrate Programme.

Experts says that natural gas recovered from gas hydrates is the cleanest-burning fuel. Initial surveys have indicated that gas hydrates in Indian offshore are about 1,894 trillion cubic metres, which is 1,900 times the current gas reserves of India.In May 2006, DGH along with the National Institute of Oceanography had undertaken drilling exercises using Oceanographic research ship `Joides Resolution' for gas hydrates explorations. DGH drilled at multiple locations along the coast including Krishna-Godavari basin and Andaman seas. They have found the presence of hydrates at various locations. The research and explorations in gas hydrates is still in nascent stage, but it is a part of the country's strategic vision. By actively carrying research in this emerging area, India wants to gain global leadership.

Geological experts have pointed out that the estimates of total global carbon based on the inferences of gas hydrates and fossil fuels from both oceans and land deposits and atmosphere is about18 trillion tonnes, of which the gas hydrates alone amounts to 10 trillion tonnes - twice that of the carbon from fossil fuels.

OilMin against making commitments in oil, gas marketing

October 23, 2006. Petroleum Ministry has opposed making any commitments in the area of oil and gas marketing by foreign companies as part of India's response in the services negotiations of the World Trade Organisation. The ministry has also suggested that if and when India offers to take commitments in marketing of petroleum products, including transportation and distribution, the government should include safeguards to ensure public safety and address the critical needs of the country.

The oil ministry conveyed its response to the Commerce Ministry, which is preparing India's negotiating strategy under the WTO's General Agreement on Trade in Services (GATS), early this month. Even though WTO talks are suspended, inter-departmental discussions are going on to finalise India's position to make sure that the country is ready whenever the talks resume. In WTO talks, a country cannot put barriers for Foreign Service provides once it has made a commitment under GATS.

The discussions are necessary to ensure that domestic regulations - such as those related to licensing and qualification requirements - do not nullify the commitments made by the country for opening up the services sector. The Petroleum Ministry has suggested including certain criteria that gives it the flexibility to bar foreign companies from marketing of oil and gas on grounds of public safety, environmental concerns or any such factor. The ministry was of the view that its existing rule under which only those foreign companies who have invested at least Rs 2,000 crore in setting up refineries or pipelines are given licenses could be included as a condition.

REL Comm plans B2C platform for oil companies

October 23, 2006. In a major business-to-consumer (B2C) mobile application initiative in the country, Reliance Communications is planning to set up a platform for Indian petroleum giants that will enable the public sector undertakings to service customers through mobile phones.  The company would create a mobile zone for the oil companies, enabling them to handle queries and complaints, sales and cooking gas bookings over the air, a first-of-its-kind in the country. 

The LPG companies have a total of around 80 million customers, while the customers of Reliance Communications stand at 26 million.  The services would be initially available to Reliance Communications’ subscribers and this will make it one of the largest B2C services in the country. Earlier, Reliance had set up a B2C initiative for India Post that tracks the position of speed post packets and booking of railway tickets through the handsets. 

Cairn India lines up $2 bn

October 23, 2006. Cairn India, the Indian subsidiary of Scottish firm Cairn Energy Plc, plans to invest over Rs 9,140 crore ($2 bn) in its prolific Rajasthan block, home to the largest onshore oil discovery in more than two decades.  Cairn plans to invest Rs 6,900 crore in the giant Mangala field alone over the life of the field lasting 2014, according to the draft red herring prospectus (DRHP) filed by the company for an initial public offering (IPO) in December.  Mangala is the largest of the 18 discoveries the company has made in the Rajasthan block, where the company estimates an in place reserve of 3.6 billion barrels. 

Cairn estimated an investment of Rs 3,960 crore would be required to commence commercial oil production from the Mangala field in 2009. Of this total, at June 30, 2006, Rs 240 crore had already been invested.  The company has classified its Rajasthan block discoveries into three broad heads - Main Northern Fields comprising Mangala, Bhagyam and Aishwariya discoveries; Small Southern fields of Saraswati, Raageshwari Oil and Raageshwari deep gas finds; and other accumulations such as GS-V, Guda, N-E, Kameshwari, Shakti, N-I, N-P, Bhaygam South, NI-North, NC West, Vijay and Vandana, NR, Mangala Barmer Hill and Aishwariya Barmer Hill. 

Currently, the Mangala, Bhagyam, Shakti, Aishwariya, Saraswati, Raageshwari oil and Raageshwari Deep gas fields are all under active development planning. The three fields together hold 2 billion barrels of oil reserves. Of the three largest Rajasthan Block fields of Mangala, Bhagyam and Aishwariya, Mangala is the first to be developed and Cairn is currently expecting first commercial crude oil production from the field during 2009, followed by Bhagyam within six months and Aishwariya within 12 months thereof. 

Cairn expects to commence commercial production in the Mangala field during 2009 with initial production of up to 50,000 barrels per day and a plateau of 100,000 barrels per day.  The field would reach 96,000 barrels per day within nine months of beginning production and would remain at the plateau for three years before the field starts to decline. 

JV for Assam gas cracker signed

October 20, 2006. A joint venture agreement for the Assam gas cracker project has been signed among GAIL (India) Ltd, Numaligarh Refinery Ltd (NRL), Oil India Ltd (OIL) and Assam Government. These entities are also the promoters of the joint venture company to implement the project. The integrated petrochemical complex proposed to be set up at Lepetkata, Dibrugarh, at a cost of Rs 5,460 crore will be implemented by a joint venture company, to be promoted by GAIL with 70 per cent equity participation.

The remaining 30 per cent equity will be shared equally among OIL, NRL and the Assam Government. The project will be completed in 60 months from the date of financial closure. The site has been identified by the State Government and necessary environmental clearance has been obtained. The feedstock for the petrochemical complex is 6.0 million standard cubic metres of gas per day (mmscmd) from OIL, Duliajan, and 1.35 mmscmd from Oil & Natural Gas Corporation up to March 31, 2012 and 1.00 mmscmd, thereafter.

The petrochemical complex would also utilise 160,000 tonnes per annum (tpa) of petrochemical grade naphtha from NRL. The complex will comprise a gas separation plant, cracker unit, downstream polymer and integrated off-site/utilities plants. The complex has been configured with a capacity of 220,000 tpa of ethylene and 60,000 tpa of propylene.

CNG retailers may get ‘limited period’ monopoly rights

October 20, 2006. The Centre is likely to allow companies have monopoly in retailing natural gas to households and CNG to automobiles for a ’limited period’, which will be decided on the basis of investment made, location and market growth. The natural gas pipeline and city or local natural gas distribution networks policy wants firms to commit long term investments based on reasonable return through network tariff, along with some incentive for earning profit from gas sales through a limited period of marketing exclusivity.

The policy would be announced this month, the exclusivity would be granted for transaction of volumes below a pre-determined threshold in a transparent manner. The downstream oil regulator would decide on the period of exclusivity based on investment made, location and market growth. The new policy was in line with the demand made by GAIL and Indian Oil, and British Gas.



Delhi Cabinet approves Bawana power plant

October 23, 2006. The Delhi Cabinet gave its approval for setting up of a 1000 MW power plant at Bawana in north-west Delhi. With the latest plant in its kitty, the government hopes that it would become self-sufficient in power in the next five years. The Bawana power plant would have three separate units, each producing 330 MW of power. The Power department has estimated that with the modern plants, 1000 MW of power can easily be generated from the plant.

The Bawana plant was conceptualised a few years ago but ran into trouble following the non-availability of gas. The Ministry of Petroleum finally suggested a company called “Petronet” to supply gas to Delhi. It would supply of 10 Million Metric Standard Cubic Meters per Day (MMSCMD) gas would be sufficient to generate around 2000 MW Gas Based power from Pragati-II, Bawana and IPGCL power stations.

The first plant to produce 330 MW of power would be commissioned in 26 months. The cost of the entire project would be Rs 1389 crores. The Cabinet approved Rs 417 crore as equity of the Delhi government for meeting the expenditure of the power project.  The Government is likely to extend a loan to Pragati Power Corporation Limited to meet the loan component of the Project.

Two power plants to be set up in M’shtra

October 20, 2006. Reliance Energy plans to put up two new power plants in Maharashtra, near the coastal town of Shahpur in Ratnagiri. REL is putting up a 4000 MW gas-based power plant at Shahpur, and a thermal plant with a capacity of 1200-1800 MW.  They were looking at sourcing both gas and coal from the international markets for the two plants.  The company was likely to come up with the thermal plant first, as coal linkages are easier than gas linkages, to firm up in the international markets.   

REL has already started acquiring land for the project and the EPC contract are in the process of given out. On the Dadri power project, the company is unlikely to complete financial closure until the gas linkages are firmed up. REL has an agreement with Reliance Industries Ltd (RIL) for gas supply at $2.38 per million metric British thermal units (mmbtu), which works out to $3.75 inclusive of all costs including transportation. The agreement which was part of the settlement between the two Ambani brothers is currently in dispute. 

The company may now be willing to consider a higher fuel cost for the Dadri plant. This could be in the range of $3.5 and $4 per mmbtu, which works out to be between $4.87 and $5.87 per mmbtu for the final costs.

DS Const bags hydroelectric project

October 17, 2006. DS Constructions has bagged the mandate to develop, construct and operate a 260 MW hydroelectric power project in Himachal Pradesh. The company won the mandate to develop the Kutehr Hydro Project on a build-operate-transfer basis through a competitive bidding process involving eight domestic and international players. The project will be constructed on the Ravi River at an approximate cost of Rs 1,058 crore, the company had made a bid for an upfront payment of Rs 52 lakh per MW for the project. The company has already started the process of preparation of the detailed project report.

Transmission / Distribution / Trade

RasGas to supply LNG to Dabhol plant from April

October 20, 2006. Qatar-based RasGas Company Ltd will supply LNG to the Dabhol power plant of Ratnagiri Gas and Power Private Ltd (RGPPL) from April 2007. RasGas will supply 1.2 million tonnes of gas per annum. Price negotiations for gas supply is currently under way but the contract would be till March 2009. The plant is expected to be operationalised by April; by the end of the month it would be able to activate its two turbines with a capacity of 740 MW each. The power production of 1,480 MW from the Dabhol plant will help Maharashtra cope with the 4,500 MW load shedding.

Power Grid to invest $2.6 bn in W India

October 20, 2006. Public sector transmission giant, Power Grid Corporation of India Limited, will invest Rs 12,000 crore ($2.6 bn) in the western region over the next three years, a third of which will be in Maharashtra.  The western region covers Maharashtra, Madhya Pradesh, Chhattisgarh, Gujarat, Goa and the Union Territory of Daman-Diu and Dadra Nagar Haveli.  The projected demand, with growth at the rate of 7.5 per cent annually as per the National Electricity Plan-Transmission of the Central Electricity Authority (CEA), has been calculated at around 23,774 Mw by 2012.

The various schemes such as the Sipta-II supplementary scheme and the Western Region System Strengthening scheme have been formulated and work towards their time-bound completion started. These schemes comprise 6,000 ckt km (circuit Kilometer) of 765/400 KV transmission lines and 5 units of 400 KV sub-stations with transformation capacity of 2,520 MVA at an estimated cost of Rs 4,700 crore. 

The new schemes will strengthen the transmission network in Maharashtra and also facilitate development of three additional transmission corridors between the eastern part of the western region to the central/western part of Maharashtra. The proposed transmission scheme will also enhance the power transfer capacity to the state to about 11,500 MW.

Policy / Performance

Plan to recast power reform scheme

October 24, 2006. The Centre is planning a revamp of its key reform tool for the power sector — the Accelerated Power Development and Reforms Programme (APDRP) — to make eligibility for financial assistance more stringent under the scheme, especially in the wake of several instances of State Governments submitting bogus claims.

Based on the recommendations of a high-level task force on revamping of the programme, the Centre is likely to consider making private distribution companies eligible under the scheme to get funds. Getting funds could, however, be much tougher as a graded level of quantifiable loss-reduction targets is likely to be incorporated as a precondition for utilities. In its report, the panel sought the continuation of the programme with investment and incentive component beyond the Tenth Plan period. It suggested that the conditions for getting assistance under the programme be made more stringent to make States adopt firm reform measures to turnaround the sector. Primary conditions include the establishment of special courts and police stations to check theft, besides which, the restructuring of SEBs and constitution and operationalisation of independent regulatory commission have also been suggested.

As per the recommendations, States will also have to commit achievement of certain secondary conditions including the finalisation of a financial restructuring plan approved by the regulator and the State Government, adoption of multi-year tariffs and 100 per cent system metering up to 11 kV feeders.

The panel also suggested that assistance under APDRP, including both investment and incentive component, may be extended to the private distribution utilities as well, which have so far been kept out of the scheme.

Besides, the task force recommended aggregate technical and commercial (AT&C) loss reduction targets of four per cent annually for utilities having losses above 40 per cent, three per cent annually for utilities having AT&C losses between 30 and 40 per cent. A reduction of two per cent per year has been suggested for utilities having losses between 20 and 30 per cent and a one per cent reduction for utilities having losses below 20 per cent. Utilities also need to prepare a roadmap with priorities for works to be taken up under the investment component and execute the work by adopting best practices.

The Government had approved the programme with a budget provision of Rs 40,000 crore during the Tenth Plan, out of which Rs 20,000 crore was allocation under investment component and Rs 20,000 crore under the incentive component. However, the Government actually allocated only Rs 12,322 crore.

BHEL’s load factor has govt worried

October 24, 2006. Keeping its ambitious plans for the Eleventh Plan in mind, the ministry of power has put Bharat Heavy Electrical (Bhel) on notice. The power ministry is worried that equipment manufacturing major may not be able to meet the sector’s needs — both in terms of quantity and quality.  The ministry has planned capacity addition of more than 70,000 MW in the Eleventh Plan. Concerns have also been expressed on power equipment major’s ability to upgrade its technology.

Bhel has a technology transfer arrangement with Alstom and Siemens for the 800MW super critical units. Bhel would like an assured commission of eight to 10 units from NTPC over which this technology transfer can take place. The power ministry considers the issue of qualitative advancement in terms of technology upgrade to be a matter of great concern. Though Bhel has belatedly been able to tie up with Alstom for boilers and Siemens for turbine generation but the company has not been successful with this arrangement in at least two international NTPC tenders - Sipat (1320 MW) and Barh (1980 MW).

NTPC had floated international tenders for super critical 660 MW unit rating for both Sipat and Barh. The BHEl-Alstom-Siemens consortia had lost out in these tenders, as their prices are substantially higher. The ministry of power is worried that when it comes to the 800 MW super critical technology, the consortia may not be competitive in its price as was the case in the Sipat and Barh international contract biddings.

Ministry would like the 800 MW technology to be transferred to the Indian manufacturing sector. They also understand Bhel’s attempt to secure six to eight units order from NTPC over which it will acquire engineering and manufacturing capability. With these concerns the ministry of power has to balance the need to keep the cost of power low.

The ministry is also worried that if the matter is not resolved now, its plans for capacity addition in the Eleventh Plan may get derailed. If this process is not concluded now, then the Eleventh plan programme may get into difficulty in the same manner as 660 MW programme ran into trouble when Bhel was not prepared with the technology collaboration in 2003-04 (that is the second year of the Tenth Plan).

Nonetheless, the power ministry maintains that the final word, whether the Bhel consortia is awarded eight to ten units by NTPC to effect a technology transfer, will be that of the NTPC board. In any case NTPC board has to be convinced about a long-term arrangement of commissioning eight to 10 units at a rate which compares with benchmark prices. Only after NTPC agrees will the ministry be involved in seeking a mega project status for the proposal and an exemption from international bidding from the Cabinet. 

More States seek ultra mega power projects

October 23, 2006. With the ultra mega power projects of Sasan, Madhya Pradesh and Mundra, Gujarat having received environmental clearance from their respective State governments, the Power Ministry will now look into the requests made by Tamil Nadu, Andhra Pradesh and Jharkhand to set up similar projects. a high-power delegation of experts would soon be visiting these States to identify proposed sites, so that the ultra mega power projects could be set up in the next five years.

Clearance from the Ministry of Environment and Forest for the two 4,000 MW projects at Sasan and Mundra is expected soon. The Ministry is also expediting the tendering process for similar power projects in Andhra Pradesh, Orissa, and Maharashtra, among other States. Sasan and Mundra are expected to generate power at a cost of Rs 1.50 per unit. The Ministry hopes to call for bids for these two mega projects by November 22 and award the contract on build-own-operate basis by December 31.

Private sector majors Tata Power, Reliance Energy, Essar, L&T, Jindal Steel and Power and GMR, Sumitomo of Japan, Khanjee Holdings of the US, China Light and Power and the state-run NTPC Ltd are among those which have expressed interest in the two projects, whose investments have been estimated at Rs 40,000 crore. Sassan and Mundra will have a combined generating capacity of 8,000 MW and benefit nine Sates.

Power Ministry plans to rope in foreign banks and export credit agencies for financing the 4,000 MW ultra mega projects that would require an investment of up to Rs 20,000 crore each. Power Ministry and Power Finance Corporation, the nodal agency for these projects, last week held a meeting with foreign banks including HSBC, Deutshe Bank, Japan Bank of International Cooperation, Bank of America and Bank of Tokyo among others.

BHEL pays $52.8 bn dividend

October 23, 2006. State-run Bharat Heavy Electricals Limited has paid a dividend of Rs 240.34 crore to the Centre for the fiscal ended March 31. The company has paid a final dividend of 145 per cent for the fiscal compared to 80 per cent in FY 2004-05, BHEL said in a release, adding, this is the highest ever dividend paid by the company. The company had reported a 41 per cent growth in its FY 2005-06 turnover at Rs 14,525 crore and a 76 per cent jump in its net profit at Rs 1,679 crore. BHEL is planning to invest around Rs 1,600 crore in modernisation and capacity expansion of its facilities. The expansion would take its overall capacity to 10,000 MW per annum from the current 6,000 MW per annum, the additional capacity would be available by 2007.

PowerMin asks states to stop overdrawal

October 23, 2006. States resorting to overdrawal of power from the grid would face disconnection of supply and load cuts in strategic cities. The regional load dispatch centres (RLDCs) have been allowed to cut supplies to states overdrawing power from the grid if they continue to do so and also if the frequency dips to 49.3 Hz. This apart, the National Power Monitoring Centre, situated at the power ministry in New Delhi, would monitor whether or not states are following grid discipline stipulations on a day-to-day basis. Those who do not follow these guidelines shall face severe load cuts. The power supply to their strategic cities will be disconnected. All states will have to ensure grid discipline to avoid grid collapse.

Following overdrawal of power by northern and western states it asked all states to follow discipline to avoid major grid disturbance. Since August 26, almost 90,000 MW of power comes to the national grid. RLDCs will ask the gas and liquid fuel based power stations to increase their power generation when the frequency goes below 49.5 Hz.

Tariff cut order puts Escoms in a fix in K’taka

October 23, 2006. All five electricity supply companies (Escoms) in Karnataka are under pressure to reduce their transmission and distribution (T&D) losses following the Karnataka Electricity Regulatory Commission’s (KERC) decision to slash tariffs in the state, barring the Bangalore Metropolitan region. Kerc’s downward revision of tariffs came at a time when Escoms sought the regulatory body’s permission for a tariff hike close to 8 per cent at 40 paise per unit for all consumers, except those covered under subsidised schemes, like Bhagya Jyothi and Kutira Jyothi. But Kerc has rejected the applications submitted by Escoms as it did not want to dump the charges occurred due to wastage, unauthorised consumption, excessive loss and theft, on the public. It has cut tariff for all consumers, including farmers using metered irrigation pumpsets (IP).

In fact, IPs consume nearly 40 per cent of the total power supplied in the state, of which only 10 per cent are metered, generating a miniscule revenue for the government. This is the first time the state has witnessed a downward revision in power tariff, which will come to effect on November 1. Kerc attributed the tariff cut to good inflow into hydro reservoirs. It also has directed all Escoms to revise the power purchase estimates, taking into account the actual inflow up to the end of August 2006. The tariff reduction is also expected to encourage entrepreneurs to prefer destinations other than the already crowded Bangalore Metropolitan region, where the tariff has not been slashed. Hundreds of small-scale units are now expected to set up shop in industrial estates being developed in Tier II and Tier III cities, like Mysore, Hubli and Hassan.

Lanco M’lore power project achieves financial closure

October 20, 2006. The Hyderabad-based Lanco group-promoted 1,015 Mw Nagarjuna Power Project at Mangalore in Karnataka has achieved financial closure.  A consortium of 14 banks and financial institutions, led by Power Finance Corporation, has financed the project loan of Rs 3,474 crore.  The coal-fired thermal project, which is to be set up at a cost of Rs 4,342-crore, is being jointly funded through a mix of debt and equity. Of the equity component, Lanco will have 74 per cent stake with balance held by the Nagarjuna group.  The project is expected to be commissioned by the last quarter of 2009.  While 90 per cent of the power generated will be supplied to Karnataka, the balance 10 per cent will be supplied to Punjab. 

CII plans captive power project in Nashik

October 19, 2006. To mitigate the power shortage problem in Nashik city, the Confederation of Indian Industry is planning to form a public-private partnership to set up a captive power plants on the lines of the project in Pune.  The pilot captive power project in Pune has successfully bridged the demand-supply gap of 100 MW per day.  Before the project was set up by 30 companies in PPP, the city used to get 550 MW daily as against its requirement of 650 MW, leaving a shortage of 100 MW.

PowerMin asks states to set up mini-ultra projects

October 18, 2006. After the successful launch of ultra mega power projects (UMPP), the power ministry has asked states to set up mini-ultra power projects, having a capacity of 1,000-2000 mw. It has assured them of providing all the necessary help through the state-run Power Finance Corporation (PFC). The ministry, however, has said that the procurement by distribution licensee from the private sector can be done only through the competitive-bidding for tariff.

The ministry said while coal block allocation had been received by the states, the tariff bids could be invited for coal mining in the allotted block and power generation project within the state. A special purpose vehicle (SPV) could take care of land acquisition, water and environmental clearances as the bidding process. Moreover, the state could also invite tariff bids on the basis of coal linkage for private sector power projects. The ministry has suggested that with the bid document and papers having been settled for the joint procurement by distribution licensees of a few states in the UMPP, the same document can be adopted by the state distribution licensees. The ministry has also offered to help the states to get requisite coal linkage/coal block.

MERC rejects plan to get power through long-term bid route

October 17, 2006. The Maharashtra Electricity Regulatory Commission (Merc) has rejected the Maharashtra State Electricity Distribution Company’s (MahaVitaran) plan to procure up to 4,000 MW of power through long-term competitive bidding route. Instead, the commission has considered the bidding process to be undertaken for only 2,000 MW, unless the demand forecast establishes the need for a higher quantum of procurement. The commission has directed MahaVitaran to prepare a detailed demand forecast by engaging experts. The methodology to be adopted should be presented to the commission for in-principle approval. Based on this demand forecast, the long-term power procurement plan including the annual rolling plan should be submitted for the commission’s approval. However, the commission observed that stipulating the location within Maharashtra alone clearly amounts to non-compliance of the requirement for adopting case-I route and also limits completion of the process.




Shell offers to buy out Canada unit for $6.8 bn

October 24, 2006. Royal Dutch Shell Plc offered $6.8 billion to buy out a Canadian venture to increase production from oil sands as violence curbs Nigerian supplies and as fields mature in the North Sea. Shell, which owns 78 per cent of Shell Canada Ltd, will offer Australian $40 a share for the remainder.

Shell Canada’s oil sands project is in a region known as the Athabasca in northeastern Alberta, where oil-laden sands are strip mined and then processed with heat and solvents to extract the tar-like crude. The unit, Canada’s fourth-largest oil company, earlier this month said oil-sands projects would remain viable should crude prices fall to $30 a barrel. As the company has sought to replenish its reserves, Shell has struggled with cost overruns, including Russia’s Sakhalin 2 venture, where it owns a majority.

AIOC starts pumping oil from East Azeri field

October 23, 2006. The BP led AIOC consortium has began pumping oil four months earlier than planned from the East Azeri field, part of the huge Azeri-Chirag-Guneshli (ACG) group of fields in the Caspian Sea. The Azerbaijan International Operating Company (AIOC) said production began at the first of eight wells in water depths of 150 metres (492 ft), and first oil would reach the Baku-Tbilisi-Ceyhan pipeline pump station at the Sangachal terminal near Baku in two weeks.

East Azeri is due to produce 260,000 barrels per day at its peak, while overall Azeri field production is forecast at over 800,000 bpd by mid-2007. The consortium began pumping oil from Central Azeri in Azerbaijan's sector of the Caspian Sea in February of 2005 and from Western Azeri in January this year. It has been pumping from the neighbouring Chirag field since November 1997 and will start producing oil at Guneshli in 2008.  The Azeri-Chirag-Guneshli (ACG) group of fields has reserves of 5.6 billion barrels of oil, which are due to be extracted by 2025. ACG is set to become the main source of crude for the Baku-Tbilisi-Ceyhan pipeline, which will pump more than 1.0 million bpd from Azerbaijan to the Turkish Mediterranean coast once it reaches plateau output in 2009.

Marathon discovery on Angola Block 31

October 23, 2006. Marathon Oil Corporation announced that its subsidiary, Marathon International Petroleum Angola Block 31 Limited, has participated in a deepwater discovery on Block 31 offshore Angola. This marks the sixteenth discovery in Marathon's deepwater exploration program on Blocks 31 and 32 which began in 2001. The Titania discovery is located approximately 165 kilometers (103 miles) off the Angolan coast in 2,152 meters (7,060 feet) of water. The Titania-1 discovery well was drilled in the central part of Block 31 approximately 25 kilometers (15 miles) south of the planned Northeast Development Area. The well was drilled to a total depth of 5,339 meters (17,516 feet) and is the second discovery in Block 31 where hydrocarbon charged reservoirs occur below thick salt. The well was flow tested under operational restrictions at a rate of 2,050 barrels of oil per day through a 20/64 inch choke. Marathon and its partners are evaluating and integrating the results of the Titania well, along with other discoveries previously made in the central and southern part of Block 31. The Company believes this discovery further reinforces the potential for additional development areas in the central/southern portion of Block 31.

The concessionaire of Block 31 is Sonangol, Angola's state-owned oil company. Marathon holds a 10 percent interest in Block 31, along with the operator BP Exploration Angola with 26.67 percent, Sonangol, E.P. with 20 percent, Esso Exploration and Production Angola (Block 31) Limited with 25 percent, Statoil Angola A.S. with 13.33 percent and TEPA (Block 31) Ltd. (a member of the TOTAL group) with 5 percent.

Zambia discovers oil, gas near Angola border

October 23, 2006. Zambia is planning to invite foreign firms to conduct exploratory drills for oil and gas after the first-ever reserves were found near the border with Angola. Samples taken at a dozen sites in the north-western provinces of Zambezi and Chavuma over the weekend confirmed gas and oil residues in the impoverished Southern African country, which has previously looked to its copper reserves as the main source of foreign currency. The exploration was initially started in 2004 following prolonged fires that affected the areas, which prompted the government to launch an investigation. While the size of the reserves is still not known, authorities hope that they can become a significant source of revenue in a country where about two-thirds of the population live on less than a dollar a day.

Sakhalin I operator proposes spending at $1.3bn in ‘07

October 23, 2006. The operator of the vast Sakhalin I hydrocarbon project off Russia's Pacific coast has proposed spending $1.293 billion in 2007, down $307 million on 2006. Capital investment in the development of the Sakhalin I deposits has reached more than $12 billion, about $8 billion less than for Royal Dutch Shell-led Sakhalin II, a sister production-sharing agreement (PSA) project that has been plagued by problems in recent months.

But the consortium running the project, which apart from U.S. operator Exxon Neftegas Limited includes Russia's state-controlled Rosneft (20 per cent), India's ONGC (20 per cent), and Japan's Sodeco (30 per cent), has upped investment to $17 billion. The figure has not been approved so far. The consortium is developing the Arkutun-Dagi, Odoptu, and Chaivo deposits on the island's northeastern shelf, with recoverable reserves estimated at 2.3 billion barrels of oil and 484 bcm of natural gas. Crude production was launched in October 2005 and reached around 44,100 barrels per day as of early 2006. Supplies to Asian Pacific countries began after a new onshore terminal in De-Kastri in the Khabarovsk Territory, the largest in Russia's Far East, was launched in October.

Chemical firm buy to boost CNOOC

October 23, 2006. China National Offshore Oil Corp the third largest oil company in China, plans to acquire the state-owned China National Chemical Construction Corporation, in a bid to strengthen its fast-growing fertilizer and petrochemical businesses and pave the way for an injection of assets to its subsidiaries.

Paramount in major Arctic gas deal, plans new firm

October 20, 2006. Paramount Resources Ltd. has agreed with two major oil companies to drill several wells on a huge tract of land in Canada's Far North, and has developed a plan to spin off its operations in the region into a new public company. Paramount, controlled by veteran Calgary oil man Clayton Riddell, it struck a deal with Chevron Corp. and BP Plc to explore for natural gas on their lands in the Mackenzie Delta region of the Northwest Territories.

Under the agreement, Paramount can earn a 50 percent stake in the properties by drilling 11 wells and gather seismic data over four years. Once that is done, the company will also get a 50 percent interest in some discoveries already made in the delta. Properties included in the agreement include EL 394, EL 427 and Inuvik Concession Blocks 1 and 2.


PetroSA in tie-up to build a new refinery by ’14

October 22, 2006. South Africa's state-owned oil and gas company PetroSA and a "private sector partner" would by 2014 build a new coal- or gas-to-motor fuel refinery to cut the country's reliance on imports. A team of cabinet ministers would within two months oversee a study to determine the refinery's size and location. The construction would begin by 2009. South Africa needs a new refinery that produces 150 000 barrels a day to meet local demand in five years if the government reaches its target of boosting economic growth to 6 percent by 2010.

PetroSA, which has a gas-to-motor fuel refinery on the southeast coast, accounted for only 7 percent of the country's transport fuel requirements. The government wanted to increase the state-owned company's share of the market to help secure energy supplies. While the energy ministry held talks over a refinery with Sasol, which supplies about 40 percent of South Africa's fuel, PetroSA's partner had not been decided on. Other companies had shown interest in investing in the plant.

The government favoured a so-called synthetic fuels refinery to make better use of the country's own energy reserves and reduce reliance on crude oil, most of which was imported from Saudi Arabia and Iran. The study will weigh the benefits of the refinery against a traditional crude oil plant. It would determine whether to build the refinery near the Waterberg coal deposits near Gauteng, which was short of refined fuel. South Africa will have a shortfall of 2.4 billion litres of petrol by 2012. It will also fall short of 2.27 billion litres of diesel and 70 million litres of kerosene.

Mexico plans to boost ethanol production

October 21, 2006. Mexico plans to wean itself off costly gasoline imports by boosting ethanol output with a government programme of incentives for the chemical and farming sectors. Despite being a major producer of crude oil and supplier to the United States, Mexico has to import about a quarter of its gasoline due to low refining capacity. It sends heavy crude to US refineries and buys back fuel. The planned government programme would provide incentives to the chemical industry and the farming sector to transform sugar, corn and other grains into ethanol.

Transportation / Distribution / Trade

China keen on trans-Himalayan pipeline

October 24, 2006. China is interested in Pakistan's proposal for a trans-Himalayan pipeline to carry Middle Eastern crude to western China. The proposed pipe would link Pakistan's deepwater port of Gwadar, which is close to the Iranian border and is partly financed by Beijing, with China's remote western regions. Pakistan also hopes to secure Chinese investment in a large refinery complex.

The route over the Himalayas would be an expensive and challenging engineering feat, and once the oil reached China it would likely have to be shipped thousands of kilometres further east to coastal areas, where most energy demand is centred. But it would allow security-conscious Beijing to reduce the portion of its oil shipped through the narrow, piracy-prone Malacca straits - which now carry up to 80 per cent of the country's oil imports. Private and state-owned Chinese oil companies are also in talks with Pakistan about construction of a refinery at the same port where the pipeline would originate - which Islamabad would like to turn into a regional energy hub.

Policy / Performance

Japan to lend Iraq $3.5 bn for oil, gas projects

October 24, 2006. Japan, which imports 99 per cent of its oil, will lend Iraq $3.5 bn to finance three projects in southern Iraq aimed at helping the conflict-stricken country boost exports. The yen-denominated loan will finance the redevelopment and upgrade of a refinery in Basra, improvements to oil export infrastructure and a project to produce liquefied petroleum gas. Japan and Iraq, which holds the world’s third largest oil reserves, will sign an agreement including the financing deal. Iraq is under pressure to reconstruct its war-torn oil facilities and boost exports and the only country in the 11- member group that does not have an Opec production target. Attacks on oil installations and the difficulty of guaranteeing security to workers have hampered Iraq’s attempts to increase production.

Iraq aims to boost crude oil production to almost 3 million barrels a day by the end of the year from 2.4 million barrels. The current output is 100,000 barrels a day higher than the level in mid-September. Oil production in Iraq peaked in December 1979 at 3.7 million barrels a day. Iraq was pumping about 2.5 million barrels a day before the March 2003 invasion by a US-led coalition. Iraq expects to pass a law outlining foreign participation in energy ventures this year. Major oil companies are not deterred by security concerns in Iraq and are waiting for the law to be enacted.

Ukraine to pay 40 percent more for Russian gas

October 24, 2006. Ukraine will pay nearly 40 percent more for Russian natural gas next year, but the price remains considerably lower than that paid by other countries. Ukraine now pays $95 per 1,000 cubic metres and officials say the country can absorb the increase. The 2007 budget was calculated assuming about $135 per 1,000 cubic meters. Gas trader RosUkrEnergo, a joint venture between Gazprom and two Ukrainian businessmen that is the exclusive supplier of gas to Ukraine, said it had contracted to provide 55 bcm in 2007. Ukraine consumes around 70 bcm of gas a year, with about 15 bcm produced domestically.

Exxon's Sakhalin-1 signs China gas deal

October 23, 2006. Exxon Mobil's Russian Sakhalin-1 project has signed a preliminary agreement with China's state oil company CNPC on natural gas supplies. The deal is a logical result of a memorandum of understanding which the companies agreed on in November 2004. It is expected that it will lead to signing an official agreement.

Exxon said earlier that under the deal, Sakhalin-1 could sell up to 10 billion cubic metres of gas to China over 20 years by pipeline. The Sakhalin-1 consortium, in which Exxon owns 30 percent, has come under pressure from Russian authorities, which analysts say is part of a broader move by the Kremlin to limit foreign involvement in the strategic energy industry. The consortium is obliged to start exports of gas in 2008 under the project's production sharing agreement, but has so far managed to sell only small volumes to continental Russia.

The plan to pipe gas to China has met opposition from Russian state gas monopoly Gazprom which has a rival pipeline project and controls all Russian gas exports apart from sales by production sharing agreements such as Sakhalin-1.Russian state oil company Rosneft, Exxon's partner with a 20 percent stake in Sakhalin-1, has previously suggested the alternative idea of liquefying gas for tanker shipments. he Sakhalin-1 group, which also includes Japanese consortium Sodeco and India's ONGC, will start full scale oil production of 250,000 barrels per day early next year.

The neighbouring Sakhalin-2 project, led by Royal Dutch Shell, has come even under greater pressure from the government and faces the threat of withdrawal of ecological permits. It is building one of the world's largest liquefied natural gas plants in the island's south.

No plans for Russia to cut oil production as OPEC reduces quotas

October 22, 2006. Russia does not intend to reduce its oil production following OPEC's decision to cut its quota to 1.2 million barrels per day from the current production of about 27.5 million barrels per day to 26.3 million barrels per day, effective November 1, 2006. Russia's oil production grew 2.4 per cent in the first eight months of 2006, year-on-year 2.34 billion bbl.

Nepal to turn over petroleum transactions to private sector

October 21, 2006. The government has brought in a bill that ends the monopoly of the Nepal Oil Corporation in petroleum products transactions and opens the way for private sector involvement. The cabinet meeting decided to send a draft of the "Petroleum Products Transaction Bill, 2063 Nepali year" to the House of Representatives for approval. Once the bill is passed by parliament, private companies will be able to import and distribute petroleum products.

This will end government control on prices which will now be determined by the market on the basis of the international market and internal competition. This will be the first law affecting transactions in petroleum products. Petroleum product transactions have so far been going on without any law. The new law will bring that under its control and provided a legal format for imports, internal supply system, determination of prices and quality levels. Conditions have been stipulated to ensure regularity in supplies from private sector companies and to discourage those wishing to get rich quick and then pull out, as well as to discourage small operators who seek immediate profits by bringing in oil tankers from across the border. The government had announced in its budget that petroleum product transactions would be thrown open to the private sector. Accordingly, the ministry prepared a draft law opening up imports, storage and distribution and all manner of transactions to the private sector and forwarded it to the cabinet. At present, Nepal Oil Corporation has a monopoly on imports and distribution is in the hands of dealers under the corporation. Under the draft law, private companies can enter into agreements with companies in India and third countries to import oil. At present Indian Oil Corporation alone supplies petroleum to Nepal.



Two power plants to be constructed in Iran

October 22, 2006. Nation’s private sector has planned to construct two new power plants in Khorramshahr and Omidieh, Khuzestan Province. The plans are in line with the Energy Ministry’s policies to have the private sector involved in the construction of power plants. Considering the increasing electricity consumption at the rate of 10 per cent plus per annum, some 4,000 MW should be added to the capacity of the state-owned electricity power plants. Some 2,900 MW will be added to the power plant capacity by the end of the current Iranian year, the state-owned capacity will reach 45,000 MW thereafter. Wind power plants are being constructed in Gilan and Khorasan provinces, and in addition to several small solar plants, a 17-MW one is part of TAVANIR projects in Yazd, central Iran.

ConocoPhillips to expand U.K. power plant

October 20, 2006. Oil giant ConocoPhillips had approved a $400 million investment to expand its Immingham, U.K. combined heat and power plant to 1,180 MW from 730 MW. Commercial operation of the expansion is expected to start in the summer of 2009. The plant provides steam heat and electrical power to the adjacent ConocoPhillips' Humber refinery and steam heat to Total's Lindsey refinery.


TransCanada seeks permits for Montana-Vegas line

October 24, 2006. TransCanada Corp. has begun the permitting process for a 3,000 MW Montana-to-Las Vegas direct current transmission line to be in operation by 2012. The high-voltage transmission line is four years in the planning so far. TransCanada filed for permits with the state. It must also file for federal and state permits from Idaho and Nevada for the project. Some of the federal permits have already been filed.

The line that will run from eastern Montana to Las Vegas will be the first of three lines in TransCanada's NorthernLights project to be constructed. The NorthernLights project comprises three long-distance, high-voltage, direct current lines. The others are a Wyoming-to-Las Vegas line and one called the from Fort McMurray, Alberta to the Washington-Oregon border. There is no timeline established for the line from Wyoming. The Celilo line to the Pacific Northwest could also be in operation as early as 2012.

Montana, Idaho and Nevada signed an agreement last spring to streamline siting and permitting for the Montana-Las Vegas line. The Montana-to-Las Vegas line and one from Wyoming to Las Vegas will converge in Borah, Idaho and then run parallel to fast-growing southern Nevada. The cost of the transmission project, including permitting and land buying, is estimated at between $1.2 billion and $1.8 billion. The Wyoming-to-Vegas line will cost about the same and also transmit about 3,000 MW.

 Policy / Performance

Florida Power to cut rates by 5 pct starting ’07

October 24, 2006.  Florida Power & Light Co. expects to cut customers' rates by about 5 percent from 2007, following revision to its fuel cost forecast due to recent drop in natural gas and oil prices.  The company now expects rates for residential customers to fall to $103.51 from $108.61 per 1,000 kilowatt hours, excluding local fees and taxes, starting in January 2007. Business customers can also expect a similar reduction.

Renewable Energy Trends


Tax incentives on bio-fuels likely

October 24, 2006. The government is mulling giving incentives like excise and import duty exemption to promote the use of biodiesel and ethanol in auto fuels so as to cut down on India’s import dependence to meet its fuel needs. The ministry of non-conventional energy sources, now re-christened as ministry of new and renewable energy, in the draft National Policy on Biofuels has suggested a slew of fiscal incentives and a National Biofuel Development Board headed by Prime Minister Manmohan Singh to promote doping of petrol with ethanol and diesel with non-edible oil. 

The ministry’s draft note for the Cabinet proposes excise duty exemption for biofuels in pure as well as blended form up to a certain percentage, with a view to lowering price of biofuels for the end user. It also proposed Customs and excise duty exemption for plant and machinery used for process oil seeds for biofuel production. Besides, excise duty exemption to biodiesel blended with duty-paid diesel, similar to the concessions given for ethanol blended petrol, is proposed to be provided.  The draft policy also proposed setting up of a National Biofuel Development Board (NBDB) to fix a minimum support price (MSP) for non-edible vegetable oil seeds required for conversion into biodiesel and other biofuels such as ethanol. 


Bid to sell renewables to China

October 23, 2006. Scottish companies stand to make millions of pounds, while helping combat to climate change, by moving into China's growing renewable-energy market. Scotland can offer "cutting-edge" technology for China's growing renewable-energy sector. China is the world's second-largest energy consumer and the third-largest energy producer. One coal-fired power station opens in China every month, although the government has said that traditional energy sources will eventually become unsustainable and that it wants to move its investments into renewable energy. Scotland has produced the first commercial wave-energy device, Pelamis, the world's first marine-energy centre on Orkney, and the world's first deep-water offshore wind-farm demonstration off the north-east coast.

GE to develop hybrid fuel cell bus

October 21, 2006. General Electric Co. formed a $13 million research partnership with the Federal Transit Administration, Ballard Power Systems and A123 Systems to develop a lightweight, battery dominant zero emissions hybrid fuel cell bus. The research will be led by GE's Global Research Center in Niskayuna. Advancements in hybrid propulsion systems and battery chemistry offer tremendous promise for enabling cleaner, more affordable transportation alternatives that will reduce reliance on fossil fuels and promote a cleaner, healthier environment.

It is expected that the hybrid fuel cell bus being designed and built will be completely emissions free, have a range of 200 miles with accessories operating, and an improved fuel cell life and cost. The focus of the research partnership will be to reduce fuel cell power requirements and improve energy storage technologies, which would help to increase the commercial viability of the technology.

GE's research effort will be aimed at reducing the high costs associated with hydrogen fuel cell development. The research partnership is part of $49 million in funding by U.S. Federal Transit Administrator James Simpson under its hydrogen fuel cell bus research and development program. GE Global Research, and its industrial partners, will contribute about half of the $13 million in funding for the project. The Federal Transit Administration, through the Northeast Advanced Vehicle Consortium, will fund the other half.

Oahu plans to build solar power plants

October 20, 2006. Energy Management Group, a local alternative energy consultant firm, signed an agreement with San Diego-based Pyron Solar to build solar power plants in Hawaii using Pyron's state-of-the-art technology. It will use Pyron's technology to build 500 MW worth of solar power plants on Oahu. If achieved, the plant would be independent of Hawaiian Electric Co., would account for about 25 percent of the island's total power capacity.


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