Energy News Monitor |Volume V, Issue 24

Energy Security in Villages through Biomass (part – II)

DR ARUN K TRIPATHI AND G R SINGH

Director, Ministry of New and Renewable Energy, New Delhi

 

 

Continued from Volume V, Issue No. 23…

 

 

ased on the total energy requirements and the local resource availability, the energy production systems are configured. For an energy production system based on biomass, an appropriate technology mix can be selected from available biomass conversion technologies such as:-

·          Single / Biphasic biogas production using tree based organic substrates, vegetable wastes / residues, vegetable wastes / kitchen wastes, animal dung etc.

·          Biomass Gasifier coupled with 100% producer gas engines for electricity generation

·          Stationary diesel engines run on straight vegetable oils or bio-diesel.

·          The energy efficient Improved Chulha for each household

·          Raising the plantations for obtaining wood, vegetable oil and other raw materials

Depending upon specific requirements, inclusion of solar photovoltaic devices such as solar lanterns or an appropriate battery backup arrangement could be considered in the system configuration.

Electricity distribution preferably to be carried out through a local mini grid. Emphasis should be on energy to be provided for productive activities with thrust on micro enterprise development, backed by micro credit facilities, with a view to facilitating job creation, income generation, increasing the purchasing capacity and reducing the migration from villages. The Guidelines for preparation of the Village Energy Plan are given in Box 2.

Formation of a Village Energy Committee

Full participation of the village community is to be secured from inception. The constitution of a Village Energy Committee (VEC) should be through the Gram Sabha and got duly notified by the Gram Panchayat as a Sub-Committee or Standing Committee of the Gram Panchayat as per the relevant provisions of the State Panchayati Raj Act and rules in this regard.

Care should be taken that the elected Panchayat member/s from that village are ex-officio members of the VEC.

 

Creation of a Village Energy Fund

A Village Energy Fund should be got created under the provisions of State Panchayati Raj Act, initially with beneficiary contributions for sustained operation and management of the project.  Subsequent monthly / annual user charges should be deposited in this account.

Grants from other Government Programmes such as rural development, forestry, tribal development, etc., if available, should be placed in this account, to be utilized towards operation and management of the project. The fund should be managed by the Village Energy Committee with two signatories nominated by the Committee. One of the signatories would be the Gram Panchayat member who is the ex-officio member on the Committee.

A separate capital account should also be got created, for receipts towards supply and installation of the energy production units. This Capital Account would also be operated by the VEC in accordance with the same procedure of joint signature and maintenance of accounts, which govern the Village Energy Fund.

Both the VEF and the Capital Account of the VEC, being the accounts of the Gram Panchayat under the provisions of the law, would be subject to the processes of accounts maintenance and audit that apply to the Gram Panchayat. Expenditure of funds by the VEC should be disclosed to the Gram Panchayat at its monthly meeting as prescribed under the Panchayati Raj Act and Rules. 

VEC, being a Sub-Committee of a Standing Committee of the Gram Panchayat would also be under obligation to disclose information in accordance with the Right to Information legislation. It will also be authorized to submit the Utilization Certificate to the Gram Panchayat, which in turn will submit the Utilization Certificate to the agency concerned at the district level. Technical facilitation and capacity building through implementing Agencies or Consultants such as NGOs would be focused at the VEC level through the Gram Panchayat.

Implementation of the test projects

The test projects are undertaken by the Panchayats/VECs duly facilitated by Implementing

Agencies such as DRDAs, forest departments, NGOs, entrepreneurs, franchises, other corporate entities, cooperatives and State Nodal Agencies. An implementing agency can forward the proposals for the test projects to the Ministry through the State Nodal Agency.

The Detailed Project Report should, inter-alia, include the following information: -

(i) Census code number of the village

(ii) Village Energy Plan

(iii) Confirmation about setting up of Village Energy Committee and creation of Village Energy Fund

(iv) Plan for training

(v) Implementation modalities

(vi) O&M arrangements

(vii) Commitment about balance 10% capital cost and funds for operation and management

The projects are owned by the village community with the responsibility for overall operation / management. However, the implementation agency helps them for about two years in this activity for which one-time Central assistance is provided. During this period, the implementing agency needs to train local youth in the operation and management of the project.

After this period, the responsibility of operation / management should be undertaken by the Village Energy Committee. The Village Energy Committee may hire / lease out these services to an entrepreneur as a preferred option. The concerned State Nodal Agency closely monitors the implementation of the projects and provide monthly progress reports to the Ministry until commissioning.

Project Costs

Different packages based on the no. of households (50-250) in the village have been prepared. For bigger villages upto 400 households, projects could be considered based on similar cost benchmarks.

However, in specific cases the applicability of a package may not be dependent only on no. of households but will have to be considered on merit taking into account the resource availability, technology configuration, load profile, layout of the village etc. The cost of project depends upon the packages based on different technology configurations for electricity generation systems, biogas plants, improved chulhas, plantations etc.

 

 

to be continued…

 

 

 

 

 

 

 

 

The Nuclear Illusion (part – IV)

AMORY B. LOVINS AND IMRAN SHEIKH

 

 

Continued from Volume V, Issue No. 23…

 

he construction challenges driving cost escalation are most formidable in the United States, currently the world leader in nuclear-revival rhetoric. U.S. nuclear manufacturing went from ~400 suppliers and 900 certifications in the 1980s to fewer than 80 and 200 today (though partly due to consolidation).⁴³ The atrophy is so advanced that some major components are available from only one or two suppliers in the world, counterfeiters are moving in,⁴⁴ and experienced subcontractors are scarce.⁴⁵

A U.S. utility executive recently remarked that he couldn’t recall any imported components in a nuclear project he ran in the 1980s, while “Now 80%…is going to have to come from offshore.”⁴⁶ Such imports don’t just challenge safety inspectors (akin to recent issues with some imported drugs); they also help to explain especially rapid U.S. reactor cost escalation. That 80% estimate, of course, was neither rigorous nor an estimate of a fraction of total project cost.

Yet in the five years through April 2008, the U.S. dollar declined by 27% against the Euro and by 12% against the yen. Had the dollar held its value as well as the Euro, the price of oil would have been under $70/bbl rather than $119/bbl.⁴⁷ The cost of reactor components imported by the United States—but not by French/German builders in Finland—reflects the weak dollar.

Nuclear workers are becoming scarce too. Forty percent of those at U.S. plants are eligible for retirement within the next five years, and only 8% are younger than 32. Two-fifths of France’s reactor operation and maintenance staff will retire by 2015, and few of the new hires are trained nuclear experts. Meanwhile, nuclear education is dwindling.

Since 1980, U.S. nuclear engineering university programs have declined from 65 to ~29 and have trouble attracting talented students; the Nuclear Energy Institute says the U.S. now has 1,900 undergraduates and 1,100 graduate students in nuclear engineering programs, but this remains far smaller than needs to offset retirements and staff proposed growth.

In 2002, the UK had no undergraduate course in nuclear engineering.⁴⁸ The number of German academic institutions with nuclear courses is expected to drop from 22 in 2000 to 10 in 2005 to 5 in 2010; 46 nuclear diplomas were granted in 1993, zero in 1998, and only two in the five years ended in 2002.⁴⁹ As experienced nuclear experts retire, safely running old plants will be hard enough without staffing new ones. 

What the World Nuclear Industry Status Report 2007 calls “rapid loss of [construction and operating] competence and lack of manufacturing infrastructure” isn’t the only big obstacle: 

The nuclear industry and utilities face challenges in a radically changed industrial environment. Today the sector has to deal with waste management and decommissioning expenses that far outweigh estimates of the past, it has to compete with a largely modernized gas and coal sector and with new competitors in the new and renewable energy sector.  

Further, many countries now expose builders to the risks of free-market competition—both with micropower and with efficient use of electricity—rather than shielding investors via traditional utility rate-basing. For example, as soon as big Tokyo customers could choose their supplier, a third of them fled from costly rate-based nuclear-dominated generation to cheaper industrial cogenerators.

Enthusiasm is no guarantee of market success: high-flying U.S. merchant (non-utility) builders of combined-cycle gas-fired plants recently wrote off about $100 billion worth of plants they’d built for which there was no demand.⁵⁰ And in the restructured markets now operating in nearly half the U.S. states and for more than half its electricity, developers must build power plants at their own risk or at the risk of a long-term power-purchasing entity. This exposure to competition raises financial risk and hence the cost of capital. This makes it “un-likely that we will see much if any investment in nuclear capacity” in those states.⁵¹

Nuclear plants worldwide enjoy unique legal exemption from liability for catastrophic accidents.⁵² The United States even offers its next half-dozen nuclear plants new federal insurance against regulatory delays,⁵³ even though meaningful public participation in licensing has already been virtually eliminated.

Yet governments cannot so easily quash uncertainties about what nuclear plants will cost and whether, once built, they can remain competitive for decades. These uncertainties deter equity investors and drive developers to high debt ratios that weaken credit ratings.

Nuclear Engineering International⁵⁴ concludes that this means “there aren’t many company boards that would give the go-ahead to a new nuclear plant.” So far, no U.S. utility’s board has done so, despite the extraordinary new subsidies described below.

A further issue arises in states that still rate-base new power plants: financial comparisons between power plants typically use levelized costs, but utility customers would feel sticker shock. A total construction cost ~$5,200/kW, near the low end of Moody’s October 2007 estimate, implies a levelized busbar cost of ~16¢/kWh. But this would require a typical regulated utility in 2013 to collect first-year project revenue of ~27¢/kWh—three times typical tariffs⁵⁵—plus delivery cost to customers. At that rate, even photovoltaics could look like a bargain.

A “death spiral” of rising price and falling demand may ensue because customers now have more choices than just buying ever more grid electricity: they can vote with their feet by buying less electricity, more efficiency, and more onsite generation—all now becoming widely available.

What are new nuclear plants’ competitors?

The MIT study compared new nuclear power only with other central thermal plants, while the Keystone study made no comparison. All nuclear advocates and most nuclear analysts, including those in the capital markets, assume that the only game in town is coal- or gas-fired central power stations. These have well-known attributes.

Coal is abundant but becoming costlier— in 2007 and early 2008, world spot prices tripled and a key U.S. benchmark price doubled. ⁵⁶ Scarcer gas has lately suffered from high and volatile prices (and, in Europe, political pressures from Russia). Both kinds of power plants, especially coal-fired ones, are also becoming considerably costlier to build.

Coal plants emit more conventional air pollution and are less efficient than modern gas plants. Burning coal contributes greatly, gas 2-4×less, to climate change.

It’s becoming much harder both economically and politically to build new coal plants, especially in the United States,⁵⁷ where three leading investment banks no longer finance them without proof that they’ll compete even under “potentially stringent” carbon pricing, and will favor energy efficiency and renewables instead.⁵⁸

Only a third of announced new U.S. coal plants are actually getting permitted or built.⁵⁹ Meanwhile, high and volatile gas prices are making gas-fired plants less attractive. The nuclear industry believes these trends should bring customers back to the atom.

However, focusing on these three kinds of central plants is obsolete. In today’s market they’re all the wrong competitors, because two other diverse classes of electrical resources are walloping all central plants in the global marketplace. These new competitors are negawatts— electricity saved by more efficient or more thoughtfully timed end-use by customers⁶⁰—and micropower— the Economist magazine’s generic term for two diverse classes of less centralized resources.

Micropower comprises two classes of technologies:

1. onsite generation of electricity (at the customer, not at a remote utility plant)—usually cogeneration of electricity plus recovered waste heat (outside the U.S. this is usually called CHP—combined-heat-and-power): this is about half gas-fired, and saves at least half the carbon and much of the cost of the separate power plants and boilers it displaces;

2. distributed renewables—all renewable power sources except big hydro plants, which are defined here as dams larger than 10 megawatts (MW).

The nuclear industry professes to support both these options, but denies they can offer serious alternatives to nuclear power because they’re too costly, too unreliable, too small individually, too slow to build, and too small in total ultimate potential. Let’s examine these claims in turn.

Notes:

43 “Supply chain could slow the path to construction, officials say,” Nucleonics Week, 15 Feb 2007.

44 R. Smith, “Utilities Fret as Reactor-Part Suppliers Shrink,” Wall St. J., p. B1, 11 Apr 2008. She quotes the Chair-man of the U.S. Nuclear Regulatory Commission: “The global supply chain is stretched, if not to the breaking point, at least to the tipping point.” 

45 “Subcontractor inexperience delayed Olkiluoto-3 projects, officials say,” Nucleonics Week, 14 June 2007.

46 Smith, ref 44.

47 Wall St. J. editorial, “The Fed’s Bender,” p. A18, 28 Apr 2008.

48 For further UK challenges, see I. Catto, “Where are the people?” Nucl. Eng. Intl. 512(637), 29 (Aug 2007).

49 These human-resources data are from ref. 4. 

50 They were misled by two disinformation campaigns. The first, by the Western Fuels Association and its surrogates like the Greening Earth Society, claimed that the Internet uses an order of magnitude more electricity than it does and will soon account for half of total demand (see Epilogue, pp. 213–219, in J.G. Koomey, Turning Numbers Into Knowledge, 2nd edn., 2008, Analytics Press, Oakland, www.analyticspress.com). The second campaign alleged that the lights went off in California in 2000–01 because that state had built no power plants in the 1990s. California actually built >4.5 GW (more than its nuclear capacity) in unnoticed non-utility decentralized capacity averaging ~35 MW/unit; the actual causes of its self-inflicted power fiasco were much simpler and more interesting (A.B. Lovins, “California Electricity: Facts, Myths, and National Lessons,” RMI Publ. #U01-02, www.rmi.org/images/PDFs/Energy/U01-02_CalifElectricity.pdf). Meanwhile, the ~200 GW of new U.S. combined-cycle plants was hit by soaring natural-gas prices. Now they run at capacity factors around 0.2.

51 P. Joskow, “The Future of Nuclear Power in the United States: Economic and Regulatory Challenges,” AEI-Brookings Joint Center for Regulatory Studies, Wkg. Paper 06-25, Dec 2006, http://econ-www.mit.edu/files/1192. The main exception is the NRG merchant nuclear project proposed in South Texas based on estimated costs roughly half those found by other utilities in 2008. 

52 This subsidy, via laws like the U.S. Price-Anderson Act, must be valuable because the industry perennially says that despite its safe operations, it cannot operate without such a liability shield. Tellingly, Koplow has shown that single nuclear operator firms buy property insurance for their nuclear plant and business that exceed by an order of magnitude the outdated coverage for their offsite liability, and that their self-coverage exceeds the entire national nuclear industry’s liability caps (ref. 186).

53 The U.S. industry has enjoyed a regulatory system of its own devising for several decades with no new orders. The U.S. Nuclear Regulatory Commission has licensed more reactors than the next four countries combined, and has never failed to approve a power-reactor license application.

54 Ref. Error! Bookmark not defined.

55 J. Harding calculation at a 4%/y real discount rate: personal communication, 15 Jan 2008.

56 S. Oster and A. Davis, “China Spurs Coal-Price Surge,” Wall St. J., p. A1, 12 Feb 2008.

57 In 2007, for example, TXU’s plans for 11 coal-fired plants in Texas were scaled back to three, whose construction remains uncertain, after a leveraged buyout encouraged by major environmental groups. California (SB1368, 2006) and Washington State (SB6001, 2007) have also outlawed long-term utility investment in baseload generation emitting more carbon than a combined-cycle plant; this policy effectively prohibits new coal-fired plants unless they reliably capture at least three-fifths of their CO2 emissions.

58 J. Ball, “Wall Street Shows Skepticism Over Coal,” Wall St. J., p. A6, 4 Feb 2008. The common assumption that “Carbon Caps May Give Nuclear Power a Lift” (R. Smith, Wall St. J., p. A4, 19 May 2008, www.climateark.org/shared/reader/welcome.aspx?linkid=99837) simply assumes that efficiency and renewables won’t be serious competitors, though it does highlight the huge market distortions that could arise if carbon emissions allowances were given to nuclear utilities and not to their nonutility competitors. The Congressional Budget Office’s May 2008 report “Nuclear Power’s Role in Generating Electricity” concludes that nuclear may undercut coal power with a $45/t carbon tax (www.cbo.gov/ftpdocs/91xx/doc9133/05-02-Nuclear.pdf), but contrary to Smith’s summary (id.), compares nuclear only with coal and central gas plants, not with “any other form of power generation.”

59 E. Schuster, “Tracking New Coal-Fired Power Plants,” NETL, 10 Oct 2007, www.netl.doe.gov/coal/refshelf/ncp.pdf.

60 Scores of utilities have demonstrated, and implemented at scale, rapid, large, predictable, extremely cheap negawatts. California’s per-capita use of electricity has been flat for 30 years while per-capita real income rose 79%— saving more than $100 billion and 65 GW of power-supply investment. Firms like DuPont, Dow, and IBM are saving billions of dollars by cutting their energy intensity, sometimes as fast as 6–8% a year. For general background, see A.B. Lovins, “Energy End-Use Efficiency,” RMI Publ. #E05-16, www.rmi.org/images/PDFs/Energy/E05- 16_EnergyEndUseEff.pdf (2005); “Negawatts: Twelve Transitions, Eight Improvements, and One Distraction,” En. Pol. 24(4):331–343 (Apr 1996), RMI Publ. #U96-11, www.rmi.org/images/PDFs/Energy/U96-11_Negawatts12-8- 1.pdf; and five detailed 2007 “Advanced Energy Efficiency” lectures as MAP/Ming Professor in Stanford’s School of Engineering, www.rmi.org/stanford.  

 

 

to be continued…

 

 

 

 

 

 

 

 

 

 

NEWS BRIEF

OIL & GAS

OVL may sign pact with Iraq for oil block allotted by Saddam

December 2, 2008. ONGC Videsh Ltd, is likely to sign agreement in next couple of months for an oil block in Iraq that was awarded to it by the erstwhile Saddam Hussein regime in November 2000. Negotiations on the contract for Block 8 in Western Dessert have been concluded and the concession agreement is ready for signing. OVL had commenced seismic survey on the block. The block, which is on the Iraq and Kuwait border, has a reserve of about 645 million barrels, of which 54 million barrels was recoverable.

The company will hold 100 per cent interest in the block and will invest $250 mn in initial exploration phase. The contract will be similar to the one China National Petroleum Corp (CNPC) signed last month for developing Al-Ahdad oilfield in central Iraq. It will be a service contract wherein OVL will be paid about 18 per cent rate of return on the investment it makes in finding and producing oil from Block 8. OVL can take its fee in kind that is in form of crude oil. OVL can practically ship of the crude oil produced from Block 8 to India.

It would act as the operator of the field until it recoups all its costs and set up a joint operating company with the local operator to take over once development costs have been repaid. Indonesia's Pertamina and state Petrovietnam, who signed two contracts in 2002 for Block 3 in the Western Desert and Amara oil field in the south, respectively, are also involved in renegotiations of oil contracts with Baghdad. Iraq has also pre-qualified OVL for its tender of eight oil and gas fields. 

Oil product sales fall as economy slows

December 1, 2008. Domestic oil product sales declined in October for the first time in 17 months as slowing economic activity crimped demand for industrial fuels and diesel. Oil product sales, a proxy for demand, fell 1.7 per cent from the same month a year ago to 10.71 mt as diesel consumption slowed to its lowest level since June, when India raised auto fuel prices by up to 10 per cent.

The fall in India's demand stands in contrast to Asian rival China, where oil consumption grew 4.3 percent in October. India's annual petrol sales in October were up 10.1 per cent to 936,500 tonnes. Diesel sales in Asia's third-largest oil consumer grew an annual 6.4 per cent to 4.24 mt, compared with double digit growth recorded in the previous month, on lower offtake by industrial users. Diesel demand is expected to ease over the next few months due to lower prices of alternative fuels naphtha and fuel oil.

India's crude imports during the month were up 13.2 per cent to 11.365 mt, or nearly 2.7 million bpd, on higher purchases by private refiners. Reliance Industries, which is ready to commission its 580,000 bpd refinery in western India, has stepped up crude purchases. Crude imports by private refiners were up nearly 55 per cent in October on year. Refined oil product exports declined 11.6 per cent to 3.15 mt. Exports by private refiners fell 7.4 per cent in October from a year earlier.

SpiceGas aims 700 gas stations

November 30, 2008. Delhi-based SpiceGas plans to invest Rs 400 crore ($80.69 mn) over the next seven years to set up about 700 gas stations in the country.  The fund will be made available through internal accrual and some outside investors. The company is targeting a revenue of Rs 1,694 crore ($341.73 mn) annually by March 2013 and Rs 3,066 crore ($618.51 mn) annually by March 2018.

It will set up about 40 stations in the first year in the states of Gujarat, Maharashtra, Madhya Pradesh, Chhattisgarh and Andhra Pradesh. The company is looking at both organic and inorganic routes for growth. The company will adopt a mixed approach with 20 per cent company-owned stations and the rest through the franchisee route. 

Oil companies to earn more profits

November 30, 2008. Oil marketing companies will earn more profits, Rs 14.89/litre on petrol and Rs 3.03 per litre on diesel, since December 1 due to falling oil prices in international markets. This is Rs 6.74 per litre more on diesel and Rs 2.38 per litre more on petrol than what they earned last month. But there will be no immediate change in consumer prices of the two fuels.

Had oil marketing companies passed on the benefit of the sharp fall in global oil prices to consumers, petrol would have cost them Rs 35.73 a litre, price last seen in June 2004. Similarly, diesel would have cost Rs 31.83 a litre, prevalent in February. But retail prices of controlled items such as petrol and diesel in Delhi are Rs 50.62 per litre and Rs 34.86 per litre respectively.

Prices of four ‘sensitive’ petroleum products (petrol, diesel, kerosene sold at ration shops and cooking gas) are controlled by the government while prices of other petroleum products are market determined. In June, when the average price of crude oil import touched $122/barrel, the government increased petrol prices by Rs 5 a litre, diesel by Rs 3 a litre and cooking gas by Rs 50 per cylinder. There was no final decision on the price revision as yet but cooking gas prices could be reduced only marginally as public sector oil companies are still losing Rs 143 on every cylinder.

The government is under pressure from the opposition parties to cut petrol and diesel prices but it is restrained by the election codes. The model code of conduct for election prohibits the government to announce or promise any financial grant that may influence voting behaviour. The model code of conduct is effective till December 24.

Mittal puts on hold investment in Vizag refinery-cum-petrochem

November 27, 2008. Having lost 17 bn pounds in the global financial meltdown, India-born billionaire Lakshmi Mittal has put on hold his investments in USD 10 bn refinery-cum-petrochemical project planned at Vizag. Mittal is, however, going ahead with investing in Hindustan Petroleum Corp Ltd's Rs 18,919-crore ($3.87 bn), 9 mtpa Bhatinda refinery in Punjab.

The five-way alliance of HPCL, Mittal, French energy giant Total, gas utility GAIL and Oil India Ltd was currently doing pre-feasibility study for the project and the partners are scheduled to take an investment decision in March 2009. While the export-oriented refinery will be of the order of 14-15 mtpa, the petrochemical plant would be of at least one million tons capacity. 

Saudi Aramco could join a planned Rs 500 bn ($10 bn) oil refinery in Andhra Pradesh. Saudi Aramco could be offered as much as 15% stake in the refinery being planned by Hindustan Petroleum Corp. Ltd. (HPCL), GAIL India Ltd., Oil India Ltd., Total SA and Lakshmi Mittal.

Oil PSUs cut jet fuel prices again

December 1, 2008. This was the sixth cut in jet fuel prices since August when rates rose to an all-time high of Rs 71,028.26 per kilolitre. Public sector oil marketing companies, IOC, HPCL and BPCL have slashed the price of Aviation Turbine Fuel (ATF) for the sixth time in three months, in line with falling crude oil prices.

In New Delhi, the state-run oil companies cut jet fuel prices by Rs 2,480 to Rs 36,900.51 per kilolitre, effective December 1. The price in Mumbai was decreased by Rs 2,584.23 to Rs38,103.19 a kiloliter.

‘India wants stability in oil price at current levels’: Pandey

December 2, 2008. According to Oil Secretary R.S. Pandey, India, a major Asian oil importer, wants global crude oil prices to stabilise at current levels and said volatility in prices was bad for both consumers and producers.

Oil has fallen nearly $100 from a record high of $147.27 hit in mid-July as worries about the economic slowdown in the United States and Japan stoked concerns about global fuel demand.

Oil companies allowed to sell bonds to RBI

December 2, 2008. IndianOil, Hindustan Petroleum Corporation and Bharat Petroleum Corporation have been allowed to sell their oil bonds to the Reserve Bank of India (as part of its special market operations) and meet their forex needs for crude and product purchases. Quite unlike the earlier practice, however, the three oil refiners will only get 50 per cent in dollars from RBI and the balance in rupees.

They can then buy their forex from the market with these rupees and fund their monthly crude and product bills. This move will ensure that not too much forex moves out of the banking system. It could also be intended to prevent high volatility in the rupee. On an average, the three oil majors buy crude worth $3 bn a month (Rs 15,000 crore) of which IOC accounts for over half of this amount with HPCL and BPCL taking up the balance.

The Government had, last month, issued Rs 22,000 crore ($4.39 bn) oil bonds to the three companies which were intended to partially compensate them for losses incurred on sale of petrol, diesel, cooking gas and kerosene at subsidised prices. Of this, IOC got Rs 11,975.51 crore ($2.39 bn) followed by HPCL and BPCL with Rs 5,330.76 crore ($1.06 bn) and Rs 4,693.73 crore ($937.43 mn) each. These bonds were only part of the Rs 65,000-crore ($12.98 bn) package earmarked between January and September. The balance Rs 43,000 crore ($8.58 bn) is expected in two tranches by the end of February.

The Government has already hinted that no more oil bonds will be issued for the rest of the year because the losses on sale of fuels have since fallen considerably. In fact, the oil PSUs have begun making profits on petrol and diesel. The companies are only concerned that the entire process of getting money against the bonds could be a long drawn out process which brings added problems of higher interest costs. They are also hoping to get a financial package which can make up for the losses incurred between October and March 2009 as well as for the balance for the first half which have not been completely compensated.

Non-domestic LPG prices cut by Rs 240-270 a cylinder

December 1, 2008. Private and public players in the non-domestic liquefied petroleum gas (LPG) business have passed on the benefit of reduction in international product prices to customers. The price of commercial LPG that is sold in 19-kg cylinder has been reduced in the range of Rs 240-270. The prices are expected to go down further in January as the LPG prices for December in the global market has gone done by another $150 a tonne and is ruling close to $340 a tonne. Originally, the non-domestic LPG prices was expected to go down by Rs 300-Rs 320 a cylinder, but due to rupee depreciation the entire benefit of the international prices could not be passed on to the customers. If the rupee was at Rs 41 versus dollar then the price would have come down by over Rs 300 a cylinder.

Commercial LPG has seen a growth of about seven-eight per cent. The decline in non-domestic LPG prices is also going to boost the auto gas sector, which saw a nil growth in the last quarter. The auto gas sector had seen a growth of nearly 40 per cent in the last fiscal. The category is expected to pick up considerably as auto gas is cheaper than petrol by almost 35 per cent.

While prices of commercial LPG (19 kg) has decreased to Rs 831.1 a cylinder from Rs 1,108.5 a cylinder in Delhi, the price of auto LPG has come down on an average by Rs 5 a litre. The auto LPG price in Delhi has been reduced to Rs 30.37 a litre (Rs 34.38 a litre).

Kerala opposes declared goods status to ATF

December 1, 2008. The Kerala Government is not in favour of the move by the Union Finance Ministry to accord declared goods status to aviation turbine fuel (ATF). The proposal is aimed at enabling the domestic airline industry to save on fuel cost. However, it will result in revenue loss to the states. If declared goods status was given to ATF through an amendment to the Central Sales Tax Act, states would be able to levy sales tax on the commodity only at the standard rate of four per cent.

This would result in a combined annual revenue loss of Rs 3,500 crore ($691.69 mn) to the states as most of them were levying more than four per cent tax on ATF. States were in the grip of financial difficulties in the wake of mounting expenses and pressure on infrastructure requirements. Besides, the recession had started adversely affecting the revenue receipts of most state governments.

Deora invites CIS investments in oil and gas sector

November 26, 2008. Murli Deora, the Union Minister of Petroleum and Natural Gas said that India welcomes participation of companies from CIS regions for investing in the country's oil and gas sector. He said that the possible areas for investments include greenfield refineries and petrochemical projects, exploration and production through New Exploration Licensing Policy (NELP). Deora also said that the next NELP round will be launched in early 2009.

The Petroleum Minister pointed out that India is seeking a greater synergy in energy with CIS countries. He also referred to the existing cooperation and projects, which include Sakhalin-I project in Russia, discussions on import of natural gas from Turkmenistan and on business opportunities in Kazakhstan, Uzbekistan and Azerbaijan, etc.

Mukesh Ambani for stable oil pricing globally

November 26, 2008. According to Mukesh Ambani globally a stable oil pricing regime was needed to sustain investments and economic growth. Energy had crucial role to play in economic prosperity and social equity and it has to available, accessible and affordable. Stable oil pricing regime was the need of the hour. According to him, availability was not an issue as 2 trillion barrels of conventional oil reserves still remained to be exploited that would be enough to support world demand for 3-4 decades.

Another trillion barrel reserves are trapped in non- conventional sources such as oil shells and tar sands. However, accessibility is an issue as most of the reserves are in hostile and remote physical environments. Crude at even USD 60 per barrel is unaffordable to many nations. One time (oil-cartel) OPEC had talked of maintaining crude oil price in a band of USD 25-30 a barrel. This would be necessary (for) economic prosperity.

POWER

GVK Power’s hydro project to go on stream before schedule

December 1, 2008. Infrastructure developer GVK Power and Infrastructure (GVKPIL) is set to complete its Rs 2,069-crore ($408.89 mn) Alaknanda hydro power project in Rishikesh ahead of schedule. Several other private infrastructure projects in the country are getting delayed as service providers are finding it tough to raise money due to the credit crunch. But GVKPIL’s Alaknanda project features in the list of few projects that are on track.

The company has also received financial commitments from international private equity players to fund the ongoing project. Foreign PE funds have expressed their interest to fund the Alaknanda project. The company had earlier infused Rs 142 crore ($28.06 mn) as promoter’s equity for the project. It raised around Rs 1,600 crore ($316.2 mn) from a consortium of 11 banks and one financial institution from India and overseas. Of this, only over Rs 400 crore ($79.05 mn) has been used so far for the project.

GVK is implementing 330 MW Alaknanda hydro power project, located 110 km from Rishikesh. It comprises four units of 82.5 MW each. The power purchase agreement (PPA) for the project was inked with the Uttar Pradesh Power Corporation (UPPCL) in 2006. The project achieved financial closure in August 2007. Bharat Heavy Electricals (Bhel) bagged the contract for electro-mechanical works. GVKPIL has diverse interests in urban infrastructure, energy, aviation, hospitality and manufacturing.

Apart from this project, the company is also developing other power projects that are based of coal and gas resources in several states including Andhra Pradesh and Punjab. GVK set up India’s first independent power project, the 216 MW Jegurupadu combined cycle power plant, with an investment of Rs 1,025 crore ($202.56 mn). The Jegurupadu combined cycle power plant-I is now awaiting gas supply from Reliance Gas Corporation. It also executed the Jaipur-Kishangarh road project that is already operational.

Nuclear Power Corporation identifies 4-5 sites to set up 1,000 MW units

November 30, 2008. Nuclear Power Corporation of India Ltd (NPC) plans to set up clusters of nuclear power plants in identified ‘Nuclear Parks’ in the country. At least 4-5 such sites that include Koodankulam in Tamil Nadu and Ratnagiri in Maharashtra have been identified to set up 1,000 MW units. As per the NPC, the potential sites would be along the coastal areas and the power produced from these nuclear plants should be competitive to thermal power in the region.

The company said that about 10 large reactors of the Light Water Reactor (LWR) are also planned with participation of global players. The company also said that discussions are on with energy majors such as GE, Westinghouse of the US; Areva of France and Russian majors and its condition for participation would be an assurance of life-time guarantee of fuel supply to the reactors. It mentioned that while the sourcing for the reactor would be from global vendors, efforts are on to ensure that indigenisation in the future nuclear power plants would be up to 80 per cent, so that Indian industry has a major role.

Under an accelerated expansion programme during the current Eleventh Plan, NPC has got the mandate to implement eight units of the Pressurised Heavy Water Reactor (PHWR) of 700 MW rating.

BHEL to set up supercritical power plant in Tamil Nadu

November 26, 2008. Bharat Heavy Electricals Ltd. (BHEL) has formed a joint venture to set up a thermal power plant in Tamil Nadu based on the supercritical technology. BHEL signed the agreement with the Tamil Nadu Electricity Board (TNEB) in Chennai. The company has partnered with TNEB to set up the plant with two units of 800 MW each. The plant will be built through turbines using the supercritical technology.

Steam turbines based on supercritical technology use less energy and generate higher pressure for greater efficiency than traditional plants. The land for the project, proposed to be set up at Udangudi in Tiruchendur Taluk of Tuticorin District, has already been identified. With a total capital outlay of around Rs 87 bn ($1.76 bn), the project will be the first supercritical power project to be installed in the state of Tamil Nadu and will strengthen the power availability in the southern state. The Boilers and auxiliaries will be manufactured by BHEL at its Tiruchirapalli and Ranipet works in Tamil Nadu.

These 800 MW coal-fired units will be able to harness the multiple benefits of higher plant efficiencies and economies of scale and will generate electricity in an environment friendly manner. The present installed power generating capacity in Tamil Nadu is 10,122 MW, of which 5,808 MW is contributed by BHEL sets. The proposed 1,600 MW capacity to be contributed by Udangudi power project will give a boost to the developmental efforts of the Govt. of Tamil Nadu. The joint venture has been registered under the name Udankudi Power Corporation Ltd.

The first of the two 800-MW units would start operation in March 2012 and the second in September. TNEB and BHEL signed an MoU for the project in October 2007. The environment impact assessment has been done and a public hearing would soon be held. The feasibility report has been finalised and a detailed project report completed soon. BHEL has already bagged major orders for power generating equipment with supercritical parameters, from NTPC for the 2x660 MW Barh Thermal Power Project Stage-II, and from APGenco for the 2x800 MW Krishnapatnam Power Project.

Coal India, power utilities inching towards fuel supply pact

December 2, 2008. Coal India and the power utilities led by NTPC seem to have moved closer to a consensus over the long pending fuel supply agreement. The deadline for entering the pact, however, is once again extended by two months from November 30 to January 31, 2009.

Central Electricity Authority (CEA) has reportedly agreed to accept the annual action plan (AAP) targets set by the Planning Commission as CIL’s total annual coal supplies to the power sector. The latter would therefore meet the additional requirements, if any, through its captive production and (or) imports. Once CEA agreed to accept the action plan targets CIL was also agreeable to set the trigger level at 90 per cent of the same.

The company had previously set the trigger at 60 per cent which was rejected by NTPC and most of the other utilities. Failure to meet the assured supply/off-take clause would invite penalty either on the seller or the buyer. CEA had further agreed to meet with all the utilities and re-allocate the annual supplies among all power plants in a manner that coal can be reached to all in the most efficient manner from CIL mines taking into account the logistics and other related issues.

The CIL has supplied 164 mt coal to power utilities between April and October, this year which was 2.5 mt more than the action plan targets. India has approximately 75 coal-based thermal power stations generating 66,000 MW, out of which 72 (64,000 MW) are catered by CIL.

Proposed power projects in Bihar may be delayed

December 1, 2008. The commissioning of proposed thermal power plants in Bihar, entailing an investment of Rs 50,000 crore ($9.88 bn), could be delayed as the work on the projects has been hit by various bottlenecks such as land acquisition and coal linkages. Going by the pace of progress, the power stations are unlikely to see the light of day before 2012.

The commissioning of plants could be delayed due to state government's unwillingness to acquire land by applying force, keeping perhaps in mind the trouble at Singur and Nandigram in West Bengal. Bihar has outrightly rejected the creation of a special economic zone. The state government has taken a policy decision that farmers giving their land for infrastructure development would be adequately compensated.

The government recently announced that a person whose land would be acquired would get Rs 1.95 lakh per acre and if donated voluntarily he would get Rs 2.40 lakh per acre. If any residential land was acquired, the land owner would get the cost of land for building house, Rs 10,000 for temporary accommodation and Rs 5,000 for carrying household goods. Out of 14 plants lined up for investment, only one plant being set up by JAS Infrastructure Capital Pvt Ltd, Patna has made some progress as it has identified 415 acres of land for acquisition.

GMR Energy to supply 200 MW power to Bangalore

December 1, 2008. GMR Infrastructure Ltd. has announced that GMR Energy Ltd. has signed a contract for supply of 200 MW power on a round-the clock basis to Bangalore Electricity Supply Company Ltd. (BESCOM), from November 16, 2008 up to January 31, 2009. Prior to this, GEL supplied 200 MW of power to Rajasthan State Electricity Board, on a round-the-clock basis from November 4, 2008 to November 15, 2008.

Coal India reintroduces long wall mining at Moonidih

December 2, 2008. As part of its renewed focus on underground mining, Coal India has re-introduced long wall mining technology at the coking coal mine at Moonidih under CIL subsidiary Bharat Coking Coal Ltd. BCCL has already awarded a Rs 436-crore ($87.07 mn) contract to Zhengzhou Coal Mining Machinery (Group) Company Limited (ZMJ) of China in this regard.

The project would produce 3.5 mt of coking coal within four years using longwall mining technology. The contract includes Rs 130 crore ($25.96 mn) for the long wall power support equipment and Rs 306 crore ($61.11 mn) for operation, maintenance and after sales support for five years with penalty/bonus clause on assured production of 0.7 mtpa. The introduction of technology is expected to bring down the cost of production at the loss making Moonidih from Rs 3,200 a tonne to Rs 1,015 a tonne.

At the current price of Rs 1,720 a tonne for raw coking coal, CIL therefore will recover the cost of the technology in two years. The share of underground production in CIL’s total production has witnessed a steady fall for last three decades. From 65 mt in 1975, underground production was 43.2 mt in 2006-07. The declining trend was arrested in 2007-08 with an underground production of 43.4 mt. The total production of the company during the year was 380 mt.

Several high capacity mines had been selected for enhanced production and expression of interest (EOI) had been floated. Under the annual action plan of the 11th Five Year plan, CIL aimed to produce around 292.93 mt coal for power sector utilities. CIL achieved production of about 164 mt of coal as against the targeted 161.5 mt. Coal demand was 253.40 mt this year as against 237.79 mt last year, up 6.6 per cent. CIL produced 236.90 mt of coal between April to November this year, as against 221.46 mt of coal in the same period, last year.

Move to tap 150 GW hydel potential to hit India's ecology badly

December 2, 2008. India's plan to tap 1,50,000 MW of hydro potential to meet its target of generating 3,98,000 MW by 2030 will bring about a major ecological disaster, according to Euro-India Economic & Business Group (EIEBG). EIEBG is a business group working in India for about a year.

According to International Energy Agency (IEA) report, India's energy demand will double by 2030 with an average of 3.8% per year. The gross power generation capacity addition would exceed 400 GW, which would be equal to the present combined capacity of Japan, Korea and Australia. According to EIEBG India is trying to over-harness its hydro capacity to meet its energy demand which will be around 3,98,000 MW by 2025-2030.

According to the group, there is the need to be cautious as over-harnessing of hydro potential has caused a major disaster in China. Although India has given priority to non-conventional power production, it has no projections of capacity addition from biomass. The group is of the view that India can generate maximum power from solar energy.

Tilaiya UMPP bids deferred till Dec 29

December 2, 2008. Power Finance Corporation (PFC), the nodal agency for the government’s ambitious plan to develop ultra mega power projects (UMPP), is set to be delayed with bids for the Tilaiya project in Jharkhand being deferred for the fifth time. The bids are now rescheduled for December 29. PFC was forced to defer the price bids as power companies have expressed concerns over the availability of funds for the project, given the current global liquidity crunch.

Bidders also want clarity over the issue of the coal transportation system in the project. PFC decided to postpone the bidding as bidders wanted more time for placing their financial bids due to concerns over raising funds and getting financial closure for the project. The additional time would also be used to clear problems being faced by the railways for setting up coal transportation network (mainly merry-go-round system) for the pit head power project.

Nine prospective bidders including Tata Power, NTPC, Reliance Power, Essar Power, L&T and Sterlite Industries are in the fray for the Tilaiya project. Only three of the bidders wanted to go ahead at this stage, while the other contenders wanted more time. As per the original plan, the government wanted to complete the bidding for Tilaiya UMPP as early as July 2007.

Earlier, the project faced some delays over identification of site, getting water source and obtaining other regulatory clearances. The delays may now impact five other UMPPs that the government intends to bid over the next few months. The Tilaiya project would require investment of Rs 16,000-18,000 crore ($3.19 – 3.59 bn). With a debt-equity ratio of 70:30 for most power projects, raising a huge amount of finances is considered difficult. The government, on its part, has tried to address the issue by relaxing norms for foreign loans by allowing companies to raise up to $500 mn through the automatic route.

Energy costs make India expensive

December 2, 2008. India will remain an expensive place of manufacturing, compared to China, due to higher cost of power, caused mainly by inefficient energy consumption, said Jean Joseph Boillot, economist and co founder of Euro India Economic and Business Group (EIEBG).

According to him, China and India were considered cheaper destinations for manufacturing, but India could be different as manufacturing could become less relevant in the near future owing to high energy usage. India lacked an aggressive plan for harnessing biomass energy, potentially a more affordable source of energy. He warned that nuclear power was not suitable for the country since it was a costlier energy source and would not help rural areas considering the cost.

Hydro projects, rural power to get priority funds

November 29, 2008. The government is re-considering the proposal to include rural electrification and hydro power projects under the priority sector lending target of banks. The proposal, earlier approved by a sub-committee of the group of ministers (GoM) on power sector-related financial issues, was turned down by the finance ministry on technical grounds. The move is expected to unlock over Rs 2,00,000 crore ($40.34 bn) for the sectors facing resource crunch.

Banks are required to lend 40% of their total loans to the identified priority sectors such as agriculture and small & medium enterprises (SMEs). The proposal seeks favourable lending from banks for rural electrification, decentralised distributed generation projects and micro hydro projects where investments in plant and machinery do not exceed Rs 10 crore ($2 mn).

A committee in the Planning Commission is considering the proposal to accelerate investments in the infrastructure sector. Its recommendations would be sent to the finance ministry and the Reserve Bank of India (RBI) for further action. The committee is likely to submit its report next month. Rural electrification is one of the flagship programmes of the United Progressive Alliance (UPA) government and a component of the Bharat Nirman programme. The programme is aimed at creating rural infrastructure such as housing, roads, telecommunications and water supply.

The finance ministry is not in favour of extending the priority sector loan status to any sector without proper distinction. The government has set up a sub-committee of the GoM on power sector to exclusively look into financing issues including upgradation of transmission and distribution networks. The sub-committee is headed by Planning Commission deputy chairman Montek Singh Ahluwalia and includes power ministers of Andhra Pradesh, Assam, Maharashtra, Orissa and Uttar Pradesh as its members.

There are several proposals to include priority lending status to sectors like power, road and aviation. All proposals cannot be entertained but specific needs of a sector can be considered. Banks already have a high credit exposure to the power sector. Their exposure to power sector is around 50% of total infrastructure financing. However, in real terms banks’ exposure to the power sector is only around Rs 60,000 crore ($12.1 bn) while their investment requirement is over 10,00,000 crore ($201.73 bn) in the Eleventh Five Year Plan (2007-12).

Once RBI clears the proposal, banks would be free to include these segments as part of their exposure to meet priority sector lending target. With banks’ total credit standing at about Rs 27,00,000 crore ($544.68 bn) as on November 7 this year and growing at over 30%, about Rs 10,00,000 crore ($201.73 bn)  would be available for priority sector lending.

 BHEL wants 15 pc duty on power equipment

November 26, 2008. State-owned Bharat Heavy Electricals is lobbying hard with the finance ministry to impose a 15% duty on imported power generating equipment in a bid to counter the increasing competition from Chinese players. Post Olympics, China has free power generating equipment capacity, which they would dump on India as the demand is high here.

As per the company, if the Indian government does not impose a duty on Chinese companies, BHEL would be wiped off after five years. Chinese equipment makers such as Dongfang Electric, Shanghai Electric and Harbin Power Equipment have already supplied equipment to the West Bengal government, Reliance Energy Limited and the Sterlite. The Chinese power equipment companies have bagged orders worth Rs 18,000 crore ($3.65 bn) from India in the past few years.

Indian companies placed orders with the Chinese companies as their power equipment is cheaper than Bhel’s. The domestic power equipment company is unable to cater to the rising domestic demand due to its own capacity constraints. It is increasing capacity to produce equipment for generating 15,000 MW power by December 2009 and 20,000 MW by 2011. Bhel has an order book position of Rs 27,000 crore ($5.48 bn) and expects to close seven power projects of 3,500 MW in four months. But the company’s growth will be lower this year compared to 41% last year.

OIL & GAS

Edison to pay $1.4bn for Abu Qir gas field

December 2, 2008. Italy's Edison SpA has reached a deal with Egyptian General Petroleum Corp to explore and develop the offshore Abu Qir gas field as it seeks to grow its gas portfolio as well as the number of its suppliers. Edison will pay $1.405 bn for the Abu Qir concession, which will be funded through existing credit lines. The concession has reserves of about 70 bcm of gas equivalent, of which Edison is entitled to about 40 percent.

Edison, Italy's second-biggest power producer and gas operator, is keen to increase its gas supplies to fuel its portfolio of gas-fired power plants and service its gas sale clients. The concession will allow the group to increase by 2013 its annual gas production to 2.6 bn bcm from the current 1.1 bn bcm. The investment needed to increase reserves and production at the field will amount to $1.7 bn, most of which will be financed over a five-to-seven-year period.

The cash flows generated by the concession will cover the investments starting from 2012. The investments made before 2012, estimated at about $750 mn, will be funded half through cash flow from the concession and half through dedicated financings. The concession, which produces around 1.5 billion bcm of gas per year and 1.5 million barrels of oil, has a 20-year duration and can be extended for a further 10 years.

Saratoga turns on taps at 2 Grand Bay wells, establishes new benchmark

December 2, 2008. Saratoga has established record levels of production for the Company of net 1,803 barrels of oil per day (BOPD) plus 7,661 thousand cubic feet per day (MCFPD), the equivalent of 3,080 barrels of oil equivalent per day (BOEPD). Contributing to these totals are the recent recompletions at SL 195 QQ#205 and SL 195 QQ#15.

The QQ#205 well was completed on November 23^rd at an initial rate of 305 BOPD, 340 MCFPD plus 3 barrels of water per day (BWPD) through a 15/64 inch choke. The Company has also begun shallow gas production from Pliocene aged sands at a depth of 1,600 feet at Grand Bay Field. The QQ#15 well was completed on November 25th and is currently producing 1,063 MCFPD plus 3 BWPD through a 19/64 inch choke.

Shell JV spies gas at Browse Basin's Libra-1

December 2, 2008. Nexus has advised that on December 2, the Libra-1 exploration well in exploration permit AC/P41 in the Browse Basin, offshore Western Australia, had reached 3,918 meters total vertical depth sub-sea (TVDSS) in a 8 1/2 inch hole. Based on logging while drilling (LWD) data, and gas shows, the well has encountered gas in a series of thick sand packages over a vertical section in excess of 180 meters gross.

Further wireline logging and pressure data is required to determine reservoir quality, column height and hydrocarbon composition. The Ocean Epoch semisubmersible rig is drilling the exploration well which is operated by Shell Development (Australia) Pty Ltd  on behalf of the joint venture.

Uruguay opens bids for offshore oil, gas blocks

December 1, 2008. Uruguay Energy Ministry and ANCAP, the National Oil Company, will launch the offshore licensing round for exploration and exploitation of gas and oil on December 1-3. The blocks on offer, lie in the Punta del Este and Pelotas basins, where water depths range from 50 to 1500 meters, as well as another basin further offshore called Oriental Del Plata.

The blocks' areas range from 2,500 to 10,000 square kilometers. In the offshore of Uruguay are situated Punta del Este basin, the southernmost region of Pelotas basin and Oriental del Plata basin. These basins are associated genetically to the fragmentation of the supercontinent Gondwana and later opening of the Atlantic Ocean. Punta del Este basin and the Uruguayan portion of the Pelotas occupy a surface area near 11.000 km2 and 15.000 km2 respectively, with a sedimentary record of paleozoic, mesozoic and cenozoic age of over 7000m. Both basins are covered by a variable water sheet from 20m to over 1000m.

In addition to new deep 2D seismic studies by Wavefield Inseis, the whole seismic, stratigraphic and structural integrated studies allowed ANCAP's technicians to establish a number of leads and plays located in offshore Uruguay in bathymetries ranging from depths less than 200 to depths greater than 1500 meters. The main exploratory situations are linked to the sedimentary sequences corresponding to the prerift, sinrift and sag evolution phases of these basins.

In South America, between Argentina and Brazil, is placed Uruguay. The government of Uruguay considered essential to prioritize the investment in physical and human capital. According to this objective, a new regulation for the Investments Law Nr. 16.906 (Decree Nr. 455/007) was passed and the Support Unit to Development and Investments in the Private Sector was created (June 2007). The new investments promotion regime, which was established in the regulation of the Investments Law, aims at granting tax benefits to companies carrying out investment projects that take into account the objectives of the economic policy.

PetroChina starts developing offshore block in Bohai Bay

December 1, 2008. According to CNPC, PetroChina Co. has started developing an offshore block in Bohai Bay with an output target of 3 mtpa or 60,247 barrels a day. The Yuedong block, located in shallow water near Liaoning province, has rich reserves of heavy oil. Yuedong is part of the Liaohe field, China's largest heavy oil field, with annual output at 12 mtpa or 240,986 barrels a day.

As an aging field, Liaohe faces depletion of reserves and needs Yuedong as a replacement. Development of Yuedong is highly risky and expensive due to active tides and a long icing period in the block. PetroChina has formulated an overall development plan for the block, including construction of four artificial islands, an oil pipeline and one land-based processing station. 

Cooper increases PEL92 production to 5,000 bopd

December 1, 2008. According to Cooper Energy, production from the prolific PEL92 production area has been boosted to approximately 5,000 barrels of oil per day (Cooper Energy share 1,250 barrels of oil per day). Following a series of successful well workovers, the PEL92 fields exported over 5,000 barrels of oil per day. The Callawonga Oil Field alone contributed approximately 4,000 barrels of oil per day to this total.

The Parsons to Callawonga 9 kilometer 5 inch flowline connects the Parsons Oilfield through the Callawonga and Tantanna facilities to the Cooper Basin pipeline system, which allows for PEL92 crude transportation all the way to Port Bonython for export. The Parsons-2 production well has also been tied into this system. The completion of the Parsons high volume artificial lift project alone is expected to boost the PEL92 Joint Venture production up to approximately 6,000 barrels of oil per day (Cooper Energy share 1,500 barrels of oil per day), subject to downstream production constraints.

Ensco 107 gears up at Maari Oilfield, first oil expected in February

December 1, 2008. Initial drilling of the Maari oil field production wells by the Ensco 107 jack-up drill rig has made good progress in the second half of November. The US$600 million OMV-operated project in offshore south Taranaki is forecast to produce 50 million barrels of crude oil at up to 35,000 barrels a day.

The Australian stock exchange-listed Horizon Oil Ltd, is a joint venture partner in the Maari project. Ensco 107 will drill 5 oil development wells and 3 water injection wells into the main Moki sands at Maari. The Maari field is located in PMP 38160, some 40 km south of the Maui gas field. First oil is expected around mid February 2009, when the first development well is expected to be completed. Partners in the development are: OMV 69%, Todd Energy 16%, Horizon 10% and Cue Energy Resources 5%.

North American Energy Resources completes second well in six well package

November 26, 2008. North American Energy Resources has completed drilling the second well of its six well package in the Mississippi Chat formation at a total depth of 1,540 feet. The well will produce both oil and gas. The Company has installed an oil separator and tank battery on the Washington County, OK property and will begin collecting oil from the well. The gas production will be connected to the Company's 75% owned Apwash pipeline. Logs indicate an additional oil show in the Wayside formation.

Spain refinery upgrades on track; more diesel seen

December 2, 2008. Spanish energy companies say that plans to upgrade refineries and reduce the country's yawning deficit in diesel are on track despite the credit crunch. Earmarked for investment by 2011 are more than 6 billion euros ($7.57 billion) to upgrade six of Spain's nine refineries run by Repsol, Cepsa and BP. Privately held Grupo Gallardo plans to open a new 110,000 barrel-per-day refinery in 2011, at a cost of 2.5 billion euros.

Along with other planned expansions, it would add 260,000 bpd in crude distillation capacity to a current total of 1.37 million bpd. According to Repsol, which is Spain's biggest refiner and operates five plants, the plans are to finance (upgrades) from cash flow. As per the Respol, the idea is to refine more, lower grade crude and produce more middle distillates.

In the 12 months to September, the latest date for which data is available, net diesel imports were 12 mt, or 33.7 percent of consumption logged by Spain's energy reserves body CORES. The only oil product in which Spain had a surplus was gasoline, for which net exports were 2.57 mt, equivalent to 40 percent of consumption.

Cepsa will spend 1.65 billion euros by 2010 to boost output of middle distillates, including diesel and kerosene, by 39 percent and up its total refining capacity by 17 percent. Repsol has the lion's share of planned investment, including 3.2 billion euros aimed at raising crude distillation capacity at its Cartagena plant to 220,000 bpd from 100,000 by 2011. Repsol, in which Lukoil has been trying to acquire a 20 percent stake, expects its upgrades to cut Spain's diesel imports by 30-40 percent.

Shell says oil sands upgrader work cuts output

December 2, 2008. Royal Dutch Shell Plc’s 155,000 barrel per day Scotford oil sands upgrader near Edmonton, Alberta, is operating at reduced levels as the company completes maintenance work on one of the facility's units. The work is expected to be completed by the end of the month and the company is producing more heavy oil than usual. Shell has also cut back production at its oil sands mining operation near Fort McMurray, Alberta. The company's Scotford refinery, which relies on the upgrader for feedstock, has secured outside supplies

US Gasoline demand increases

December 2, 2008. U.S. retail gasoline demand rose last week as the average price for gasoline dropped below $2 per gallon, according to a MasterCard report. American motorists pumped an average of 9.359 million barrels per day in the week that ended November 28, up 1.7 percent from the previous week as average gasoline prices dropped 16 cents to $1.85 per gallon, the SpendingPulse report by MasterCard showed.

The average price for gasoline, which has been well above year-ago levels for much of the year, is now 40.1 percent lower than it was one year ago. The four-week moving average for gasoline demand dropped 2.1 percent from year-ago levels. The one region that was the exception to the rule was the West Coast, where demand was down 4 percent as gasoline prices remain comparatively high at an average of $2.08 per gallon.

Lukoil pays first tranche for ERG refinery

December 1, 2008. Russia's Lukoil has made the first payment for its 1.35 bn euro ($1.71 bn) buy of a 49 percent stake in the Sicilian oil refinery owned by Italy's ERG. Lukoil paid the amount of 600 million euros ($760.3 million) as (the) first installment of the established price. The remaining sum due to ERG will be deferred and paid in three tranches before the end of September 2009.

Vietnam's first refinery gets crude for test run

December 1, 2008. The first ever Dung Quat Oil Refinery in central Quang Ngai province of Vietnam, run by the Petrol Vietnam Group, received 80,000 tons of crude oil, serving for its test-runs. The Dung Quat oil refinery will get four million tons of crude oil from the Bach Ho (White Tiger) oil field for its one-year test- running period, said the Vietnam Oil and Gas Group.

The Dung Quat oil refinery will kick off its official operation in 2010, with a plan to produce 5.7 million tons of petrol and oil of international standard to primarily serve domestic demand. The country's first refinery is designed to be capable of refining 6.5 million tons of crude oil annually, which are expected to meet around 30 percent of local demand for fuel. So far, the Dung Quat refinery has almost 98 percent of its construction workload completed. It is expected to start commercial operation by late February, 2009.

CB&I, Hoegh target Q2 for decision on floating LNG plant

November 29, 2008. Chicago Bridge & Iron Co NV (CB&I) and Norwegian shipper Lief Hoegh plan to take a final investment decision (FID) on building a floating liquefied natural gas plant in the second quarter of next year. Hoegh is talking to gas suppliers and offtakers, and by the early part of the second quarter they should have FID. LNG is gas chilled to its liquid form for ease of transport beyond the reach of pipelines.

Floating LNG projects allow for gas to be explored in areas -- onshore or offshore -- that are too small to be developed by conventional means. While yet untried, producers hope they will take less time to build, roughly three years versus eight to 10 years for conventional LNG projects, and may even be cheaper than onshore alternatives. A floating LNG production facility would cost about $800 per tonne per year (tpa).

Flex LNG Ltd, which is poised to build the world's first floating LNG production facility with its Nigerian joint venture with Mitsubishi Corp and Peak Petroleum, estimates it will cost $550 to $700 per tpa, less than what the company says onshore plants cost -- at more than $1,000 per tpa. Royal Dutch Shell and Inpex are also planning to build floating LNG projects

Pacific trail seeks interest for Kitimat pipeline

December 2, 2008. Pacific Trail Pipelines (PTP), operator of a proposed natural gas pipeline in Canada, is seeking expressions of interest for capacity in the pipeline. The C$1.2 billion pipeline will supply gas to the Kitimat liquefied natural gas (LNG) export plant in British Columbia and will increase the capacity of PTP's existing pipeline capacity in the area. PTP will accept expressions of interest until December 22, 2008.

Kitimat LNG, wholly owned by Galveston LNG, expects to start reviewing interest in mid-December. Pacific Trail Pipelines is a partnership between Pacific Northern Gas Ltd and Galveston LNG. LNG is natural gas cooled to liquid for transport in specially designed tankers and then regasified at a terminal for transport ashore through pipelines.

Gazprom holds talks on construction status of Gryazovets-Vyborg pipeline

December 2, 2008. Gazprom Management Committee held a meeting at the Gazprom Headquarters dedicated to implementing the project for the Gryazovets-Vyborg gas pipeline construction and developing the gas supply to the Kaliningrad Oblast. The meeting brought together the Gas Transportation, Underground Storage and Utilization Department, and the relevant divisions of the Gazprom Administration, as well as Yamalgazinvest, Gazprom invest Zapad, Gazkomplektimpex and Giprospetsgaz.

The meeting participants discussed the current construction status of the Gryazovets-Vyborg gas pipeline to be utilized, inter alia, for gas conveyance to the Nord Stream gas pipeline. It was noted that the pipeline construction was progressing on schedule. The current year will see the commissioning of some 165 km of its line pipe, at the same time the total length of the completed and brought onstream linear part of the Gryazovets-Vyborg gas pipeline will total some 475 km.

The meeting also addressed the progress in developing the gas supply to the Kaliningrad Oblast. It was emphasized that expansion of the gas transportation capacities and creation of the Kaliningrad underground storage facilities were being implemented in line with the previously defined deadlines. Based on the meeting results the Gazprom relevant divisions and subsidiary companies were authorized with the tasks aimed at maintaining the projects implementation.

SESH to hold expansion open season

December 1, 2008. Southeast Supply Header, LLC (SESH), a 50/50 joint venture between affiliates of Spectra Energy Corp and CenterPoint Energy, Inc., announced that it is conducting a non-binding open season for a proposed expansion along its existing 274-mile pipeline system. The pipeline currently extends from CenterPoint Energy's Perryville Hub, near Delhi, La., to the Gulfstream Natural Gas System, LLC, interconnection near Coden, Ala.

The SESH pipeline is strategically positioned to provide flexible and economic transportation solutions to meet the energy needs of the southeast U.S. The SESH pipeline provides these markets with access to a diverse array of onshore supply basins and multiple interconnections with major north-south pipelines, and with high deliverability storage facilities. Through these interconnections, the SESH system provides enhanced supply flexibility and offers scalable solutions to meet the needs of its customers.

During the open season SESH will accept non-binding nominations for service from any existing or proposed receipt points to any existing or proposed delivery points on the SESH system. The specific scope of the expansion will be finalized following the results of the open season. The target in-service date would be as early as mid-2011.

BP  will  back  CPC expansion if allowed to sell its stake

November 29, 2008. Oil major BP will back the long-delayed expansion of the CPC pipeline from Kazakhstan to Russia as early as December if it faces no obstacles in selling its stakes in the pipeline venture. Most of the shareholders of the Chevron-led pipeline, which runs to the major Russian Black Sea port of Novorossiisk, have agreed on the expansion terms demanded by Russia.

BP, the only shareholder that still opposes the terms, has said it was considering selling the stake if no compromise was found. The group's shareholders hope to sign the memorandum on CPC expansion at their meeting on December 17. BP wants to sell its stakes in CPC to Russian oil major LUKOIL and Kazakh KazMunaiGas but needs the sale to be approved by all other private and state shareholders of the pipeline consortium.

BP supports the principles of CPC extension only if it has a clear and unencumbered right to sell its stake to a selected group of companies. BP was in talks with LUKOIL and KazMunaiGas to sell its stakes in its joint ventures with the Russian and Kazakh companies, LUCARCO and Kazakhstan Pipeline Ventures, which are members of the consortium. BP's stakes in the ventures bring its share in CPC to 6.6 percent.

Russian pipeline monopoly Transneft, which holds the country's 31 percent stake in CPC, had long opposed the plan to double the pipeline's capacity from the current 700,000 barrels per day, but it has now dropped its objections. Transneft previously argued that the pipeline yielded low returns and that expansion would add pressure on the already congested Turkish Straits shipping route.

In summer, most of the partners agreed to raise the shipping tariff to $38 per tonne from $30.24 last year and private investors agreed to halve interest rates on a $5 billion loan to CPC to 6 percent, easing worries over funding. Transneft, which owns all pipelines on Russian territory except CPC, has said BP was insisting on borrowing more to fund the expansion. Chevron holds 15 percent in CPC. Its private shareholders also include Royal Dutch Shell, ExxonMobil and Russia's largest oil producer, Rosneft.

 

Iran, Malaysia sign LNG and refinery deals

December 2, 2008. Iran and Malaysia have signed three memoranda of understanding aimed at boosting cooperation in the oil and gas sectors. The MoUs were signed between National Iranian Oil Co., or NIOC, National Iranian Gas Export Co., NIGEC, and Malaysia's SKS Co. The MoUs cover buyback agreements worth $5 billion-6 billion for the upstream sector and $6 billion-8 billion for the downstream sector. Iran is expected to export 250,000 barrels a day of heavy crude oil and 120,000 barrels a day of gas liquids to Malaysia, in accordance with one of the MoUs between Iran and Malaysia.

The first MoU is a framework agreement for cooperation between NIOC and Petrofield LNG Co. Under this MoU, the two sides aim to develop the Golshan and Ferdowsi gas fields and establish LNG production units. The preliminary agreement also includes setting up a joint shipping company to transport LNG. The third MoU covers the refining of the Iranian heavy and ultra-heavy crude oil at Keda refinery in Malaysia.

China's natural gas market set to achieve balance by 2015

December 1, 2008. The demand and supply on China's natural gas market will be basically balanced by 2015, with the supply of commodity natural gas for sale to reach 229.5 bcm and the consumption to be 231.4 bcm. China would have 129.5 bcm of commodity gas for sale in 2010 including 90 bcm from PetroChina.

It is predicted that China would consume 231.4 bcm of natural gas in 2015 accounting for about eight percent of overall national energy consumption, in comparison to 3.3 percent in 2007. China would continue to face tight natural gas supply in 2010 though Sinopec is expected to provide 19.5 bcm of gas for sale and CNOOC to offer 19 bcm for sale. However, the supply and demand will be roughly balanced in 2015 when the imported natural gas is put in place.

Putin clears new Baltic pipeline to cut oil transit

December 1, 2008. Russia's Prime Minister Vladimir Putin signed a decree ordering the construction of a new oil pipeline to the Baltic Sea, designed to further cut exports of Russian crude via Ukraine, Belarus and Poland. Putin ordered a one million barrels-per-day pipeline be built to the Baltic port of Ust Luga, near Russia's largest oil port of Primorsk, with the first stage to ship 600,000 bpd from the third quarter of 2012.

The project would be financed mainly through the issuance of long-term rouble bonds by pipeline monopoly Transneft to be allocated via a closed subscription mainly to state financial institutions. Transneft designed the project nearly two years ago after a pricing dispute with Belarus briefly disrupted deliveries of Russian crude via the Druzhba pipeline to Poland and Germany. Since then Transneft has also said the project would help reduce Russia's oil transits via Ukraine as well as re-exports of Russian crude via Poland.

Putin's approval is a big boost for Transneft, which also needs to find billions of dollars to finish building Russia's first pipeline to Asia and has been negotiating a $10 billion loan with China as part of a broader crude supply deal.

Crude oil slips below $52 per barrel

December 1, 2008. OPEC defers a decision to cut output for another two weeks. It has postponed a decision until Dec. 17 to gauge the impact of a 1.5 mn barrel cut agreed in October. Oil prices fell below US$52 per barrel after the Organisation of Petroleum Exporting Countries (OPEC) deferred a decision to cut output for another two weeks.

As per the OPEC, slowing global growth means demand will be much lower than expected a month ago. Crude oil for January delivery fell as much as $2.65, or 4.9%, to $51.78 per barrel in electronic trading on the New York Mercantile Exchange. It was at $52.04 a barrel at 11:16 a.m. in London.

On Nov. 21, it touched a three and half year low of $48.25. The Organisation is of the view that oil demand is likely to drop further next year. The global market is oversupplied by more than 2 mn barrels per day. New York oil futures have tumbled 64% from their July 11 record of $147.27 a barrel as the US, Europe and Japan entered their first simultaneous recession since World War II. Oil prices fell almost 20% in November and 32% in October.

‘New refinery part of $44 bn Mexican infrastructure plan’: President

December 1, 2008. According to Mexico's President, Felipe Calderon, the government will invest about 590 billion pesos ($44 billion) in infrastructure projects next year as it looks to offset an expected slowdown in the Mexican economy due to the global financial crisis. The federal government is going to use public spending to boost the economy.

The Bank of Mexico has forecast economic growth of 0.5% to 1.5% for 2009, while the Finance Ministry has put growth at 1.8%. The central bank and ministry both expect the economy to grow 2% this year, down from 3.2% in 2007. Mexico's economy is already showing signs of a slowdown as the U.S. - its No. 1 trading partner which receives about 80% of Mexico's exports - looks headed toward a deep recession.

Calderon said major infrastructure projects for next year include breaking ground on a new metro line in the capital of Mexico City and two suburban train lines in the Valley of Mexico. He also said that for the first time in nearly 30 years the country will start construction of a new refinery that, besides generating jobs, will allow us to reduce fuel imports. Mexico has a network of six refineries but still has to import more than 40% of its gasoline to meet domestic demand. Mexico's oil industry is dominated by state run Petroleos Mexicanos, or Pemex, which has a constitutional monopoly on hydrocarbon exploration, production and refining.

Oil and related taxes account for over a third of the federal government's annual revenues. Pemex has struggled to replace output from aging fields due to a lack of investment in exploration and field development in recent decades. For the first 10 months of the year, average production was down 9.6% to 2.82 million barrels a day, due to a 31% drop at the giant Cantarell oil field. Oil exports were at 1.43 million barrels a day in October.  

Russia may work with OPEC on output cut

November 26, 2008. Russia's energy minister, Sergei Shmatko, said that the country may coordinate oil production cuts with OPEC to help stem the slide in crude oil prices. He blamed the steep decline in crude oil prices on recessions in major economies and speculation in the oil market. He said that today's oil prices are not determined significantly by traditional parameters of demand and supply but it is under effect of the whole financial crisis and speculation.

Even after the 13-nation Organization of Petroleum Exporting Countries cut oil production by 1.5 million barrels a day last month crude oil prices have fallen to about $50 a barrel - a third of their July peak of nearly $150. He pointed out that many of the budgets of oil producing countries have been balanced based on the oil price band of between $70 to 90 per barrel.

He also mentioned that Russian investment has also been budgeted at $70 per barrel. Shmatko also said that Russia was planning to form a cartel of gas producing countries along with Iran and Qatar. He is of the view that in the forthcoming years, there will be a significant fall in oil prices. 

POWER

Grid-connected photovoltaic power plant built in Hubei

December 2, 2008. Hubei's first grid-connected photovoltaic power plant, currently under construction in Optics Valley in Wuhan, Hubei Province in China, has recently been approved by experts and is expected to be operational next May. Different from common energy-efficient buildings, the four buildings located in the Wuhan Rixin Technology Company's Photovoltaic Industrial Park all have their screen walls, ceilings, doors and windows built with photovoltaic structuring. They will be able to produce 1.8 million kilowatt-hours of electricity upon completion.

The project, with an installed capacity of 1.2 MW, involves a total investment of 66.05 million yuan. The annual electricity-generating capacity will reach 1.6-1.8 million kilowatt-hours. The grid-connected photovoltaic power plant, currently China's largest grid-connected BIPV (Building Integrated Photovoltaic) power project, has been classified as a project financed by the Ministry of Science and Technology, the Ministry of Housing and Urban-Rural Development and the Ministry of Finance.

The grid-connected BIPV electricity-generating technology can be applied in public buildings such as industrial factories, urban residences and new buildings in rural areas. The energy section of the Hubei Development and Reform Commission disclosed that Hubei will spearhead the testing of grid-connected photovoltaic electricity generation after the project is completed.

Study  says competition good for electricity consumers

December 2, 2008. Retail electric competition has helped put downward pressure on the price of electricity for Texas consumers. Intelometry Inc., a Houston-based consulting and software company serving the energy industry, compared the price of service in the regulated rates of three electric utilities from 1995 to 2001 with the price of service in competitive markets in Texas from 2002 through August 2008.

The study found that the primary price component analyzed in the study (the cost of power generation) decreased as much as 13 percent in the latter period, following the inception of retail electric competition in 2002. The study notes that the overall price of residential electric service has increased since 2002, but it attributes the increase to factors other than retail competition, notably the significant increase in the price of natural gas. The price of natural gas in August 2008 was more than three-and-a-half times the fuel’s price in January 2002.

California grid operator set to overhaul real-time market

December 2, 2008. California's electric grid operator plans to seek federal approval this month to launch a new, improved real-time power market system early next year. The California Independent System Operator (ISO) wants to launch the system, called the Market Redesign and Technology Upgrade, March 1. The new system will improve the operator's current real-time power market and include a new forum for utilities and power producers to buy and sell power a day in advance.

It also will change the way power deliveries are priced. The system, particularly the transmission pricing changes, will make California's real-time power market more fair for producers and utilities, said the California ISO. It will provide the right signal to get new generation sited, new transmission put in place, and also integrate renewables and provide a level playing field for demand response participation. The ISO is essentially a broker for last-minute electricity deals between utilities and power producers.

Utilities generally turn to the California ISO's real-time electricity market when power plants or transmission lines they rely on shut down or are curtailed unexpectedly, and they need extra power fast. California's real-time market accounts for only about 5% of the state's electricity deals, but because it provides last-minute power services, it's a crucial piece of the state's power system.

Under the new system, power deliveries will be priced based on the distance between the generator and the delivery point, measured in "nodes" or geographical markers. Real-time power deliveries in California are currently priced according to whether they occur within one of three zones, or cross from one zone to another. The new pricing system uses 3,000 different geographical nodes to assign a delivery price to a power delivery.

The new system's tighter focus will allow the ISO to identify areas of California's transmission system that need to be expanded to handle more traffic, and areas that need more power generation. The state's three large utilities, owned by Edison International (EIX), PG&E Corp. (PCG) and Sempra Energy (SRE) have asked the ISO to be vigilant in watching pricing anomolies to ensure no one is exercising "market power" or taking unfair advantage of other market participants.

The Electric Reliability Council of Texas, which operates Texas' real-time power market, recently decided to move to nodal transmission pricing after spot wholesale power prices there spiked last summer owing in part to transmission congestion and the way it was priced.

Electricity tariffs adjusted

November 28, 2008. According to Public Utilities Corporation (PUC), water and electricity bills received from December 1 onwards will reflect between 20% and 35% increases. Electricity consumers will on average pay 20% more and water bills will show a 30% increase. The rates for electricity will be adjusted every month while those for water will be reviewed every three months.

The electricity rate reviews will be more frequent because of the rapid manner in which oil prices change and the water rates are higher because besides using electricity to pump water, the PUC also needs chemicals and other materials whose prices have gone up. The discounts given for the first 300 units of electricity used were costing the PUC R1.5 million monthly but have now been removed.

The discount was meant for those who could ill afford electricity, but the reductions were being enjoyed by all consumers. But now people who have difficulty paying are expected to seek help from the Social Welfare Agency. The PUC was forced to revise the rates to recover its costs, which have risen with the increased cost of fuel.

The rate for the first 300 units of electricity was R1 per kilowatt hour because the PUC was giving a 30-cent discount, which has now been removed, so the increase for the initial 300 units is going to be 40 cents per unit. It is no longer possible for the PUC to sustain the R90 discount for the first 300 units. The rates for electricity were last revised in August and for water in January. The PUC said that the government has not subsidised electricity production for over 11 months now.

CBP scheme to be applied for electricity pricing in Vietnam

December 2, 2008. Ministry of Industry and Trade (MOIT) has submitted to the Prime Minister a plan on building up the competitive electricity generation market in Vietnam. The ministry has also suggested three projects to restructure the electricity industry. According to the Ministry of Industry and Trade, after thoroughly studying Vietnam’s electricity industry, its goals and capability of building a power market, and legal framework, with the direct consultancy of international consultants and the World Bank and Asian Development Bank (ADB), MOIT has decided to apply the cost-based pool scheme (CBP) for electricity pricing.

Under the scheme, all power plants with the capacity of 30 MW and higher will have to bid prices on the market, except the BOT (build-operation-transfer) power plants. Electricity generation units will sign contracts on selling electricity with the only buyer. Power plants with have different modes of investment (thermopower, hydropower, multi-functional hydropower plants and BOT plants) will have to offer prices in accordance with different principles and with different ceiling and floor prices, which aim to avoid sudden price increases on the market.

Leaders of MOIT believe that CBP is the optimum model. They say it will allow electricity stability and avoid unexpected price increases, while minimising risks for investors. MOIT has also suggested three plans to restructure the electricity industry to make it suitable to the competitive power generation market and the CBP scheme. MOIT has suggested assigning the National Load Dispatch Centre to give advice to the MOIT on the issue of state management, in order to ensure the safe, effective and stable provision of electricity.

The centre also has the function of reporting to the Ministry of Industry and Trade, so that the ministry can submit plans on electricity price retailing to the government for approval. The centre will also have the function of verifying and assessing the power development strategies in provinces and cities put under central management.

Power tariffs to double in S. Africa

December 2, 2008. According to South African Government, electricity tariffs in South Africa will double within three years, urging consumers to use less power as the country grapples with a crippling energy shortage. The government has already approved a 27 per cent hike in electricity tariff this year. The announcement came at the start of a government programme to encourage South Africans to cut down on their power use, as the state-run utility Eskom prepares for its annual maintenance in January.

Last January, the country suffered widespread blackouts that forced Eskom to ration power and shut down the key mining industry for a week. Households account for more than a third of all electricity usage. The government says if homes adopted energy-saving measures, South Africa could reduce its electricity needs by 19.5 per cent. Eskom has launched an ambitious scheme to spend 343 billion rands ($37.2 billion) over the next five years to build new power plants and expand the transmission lines.

Work together and save electricity: Dy. President

December 2, 2008. According to Deputy President Baleka Mbete, work together to save power and cut out the waste. Immediate way South Africans could help was through simple behavioural changes to halt unnecessary power use, or even wastage, of electricity. Eskom, the national power utility, needed to increase power savings to allow maintenance of electricity plants in January.

For its part, government had refitted 4 000 buildings, saving what the deputy president said was R56-million a year in electricity costs. For businesses, government is providing free technical support to identify ways to save electricity. Government is also exploring tax incentives for more energy efficient production. Government was also trying to re-shape electricity tariffs to encourage more efficient electricity usage. Government planned to work with civil society, churches, organised business and labour to save power and allow society to benefit from a safe and security supply of electricity.

Regulator freezes prices of gas and electricity

December 1, 2008. The energy regulator has announced there will be no increases in the price of gas or electricity next year in Ireland. The Commission for Energy Regulation (CER) has turned down price increase applications of 5.6% and 3.9% from the ESB and Bord Gáis respectively. According to the CER, the price of gas supplied by Bord Gáis to residential customers and small businesses would not be increased in 2009 and there would be a small average decrease, of just less than 1 per cent, in the price of electricity supplied by ESB.

In making its decision, the Commission had taken into account recent falls in the price of gas, coal and oil on the international fuel markets. The Commission says electricity prices should fall by up to 2%, thanks to a €300 mn rebate and the sale of a number of ESB power stations. The regulator had also been careful to ensure prices are cost reflective so as not to distort competition in the retail gas and electricity markets. In early November Bord Gáis had proposed a price increase of on average 3.9 per cent, while the ESB had proposed a 5.6 per cent increase. Employers’ group Ibec also welcomed the decision but expressed concern that energy costs in Ireland continued to damage competitiveness.

‘True cost of electricity needed to sustain privatization efforts’: IFC

November 27, 2008. According to International Finance Corp. (IFC), the government needs to reflect the true cost of electricity in the power generation rates of state-owned National Power Corp. (Napocor) if it wants to sustain its privatization program. Regulators should update the present tariffs of Napocor and enforce an automatic cost recovery scheme in order to keep electricity rates up to date.

Napocor currently recovers its fuel and foreign exchange costs through deferred accounting adjustments comprised of the Generation Rate Adjustment Mechanism and the Incremental Currency Exchange Rate Adjustment Mechanism, respectively. These pass-though costs have to be filed for applications before the Energy Regulatory Commission (ERC) on a periodic basis.

Campco plans wind energy production

December 2, 2008. Central Areacanut and Cocoa Marketing and Processing Cooperative (Campco) Ltd is treading an unusual path to become self sufficient in power consumption. The cooperative will be setting up a wind energy plant at Hoovina Hadagali in Bellary district in Karnataka. The cooperative has signed a memorandum of understanding (MoU) with Suzlon for setting up a wind energy plant.

The 1.25 MW plant would come up at Hoovina Hadagali. The power produced will not be sold. After wheeling it, the power will be used for its chocolate factory in Puttur. The electricity produced at Hoovina Hadagali will be supplied to the grid and used for its factory consumption. The Campco board has already adopted a resolution in this matter. Around Rs 7 crore ($1.39 mn) will be invested in this project. The generation cost at the proposed Hoovina Hadagali plant will be to the tune of Rs 1.78 per unit. Another seven per cent wheeling charge will be added to this.

Wind power body asks TN electricity regulator to hike tariff

December 1, 2008. The Indian Wind Power Association, while welcoming the Tamil Nadu Electricity Regulatory Commission (TNERC) order approving its petition seeking permission to let wind energy generators bank energy, has asked the commission to hike the tariff to make investments in wind mills viable in the State.

According to the association, the TNERC, through an order on November 21, has directed the Tamil Nadu Electricity Board (TNEB) to let the wind energy generators use the banked energy in five equal monthly instalments from December 2008 to April 2009. In its petition, the association had said that following the acute shortage of power in the State, the TNEB, which imposed restrictive and control measures with effect from November, had ignored the banked energy while working out the quota of power that can be used by the units with captive wind power generation facilities.

Banked energy is the surplus energy that wind energy generators produce over and above their own consumption during the windy season. Under the wheeling agreement with TNEB, the generators bank the excess power during the season and use it during the non-wind season, after paying the banking charges. The petition also pointed out that other captive power generators were allowed to use the power generated by them over and above the quota fixed by the electricity board.

The association has also asked the regulatory commission to fix a tariff of Rs 3.90 a unit as the present tariff of Rs 2.70 a unit paid by TNEB to the wind energy generators had not been revised since 2001. The association said that the cost of wind electric generators has increased to Rs 6.75 crore ($1.33 mn) a MW from Rs 4.50 crore ($0.88 mn) earlier and interest rates had increased to 14 per cent. It is because of the unviable tariff and restrictive practices of the TNEB that expansion of wind energy capacity in Tamil Nadu had been affected in the last two years while Gujarat and other States were seeing high growth in capacity addition.

Textile mills for uniform power cut of 20-25 pc in Tamil Nadu

December 2, 2008. According to the Southern India Mills Association (SIMA) imposing a 20-25 per cent uniform power cut across the State of Tamil Nadu would be an ideal solution to tide over the power crisis. It is of the view that the diesel captive power generation model recommended by SIMA would provide relief to the State.

The order of the Tamil Nadu Electricity Regulatory Commission (TNERC) with regard to utilisation of banked wind energy generated between April 1 and October 31 in five equal monthly instalments during December 1 to April 30, 2009, by enhancing the demand and energy quota proportionately was a major relief to the textile industry which accounted for 75 per cent of the wind turbine generator capacity installed in the State (over 3,000 MW).

TNERC to verify the data provided by TNEB with regard to actual generation, shortage and distribution of power shortage across the industry and ensure equal distribution of power and draw up principles and protocols in line with the Maharashtra State Electricity Regulatory Commission for load shedding and power cut to minimise the losses incurred by the industry.

According to SIMA a uniform power cut of 20-25 per cent would be an ideal solution. The diesel captive power generation model would be the ultimate solution to tide over the power crisis in Tamil Nadu for the next three or four years. But with the proposed power restrictions, the textile industry would be able to achieve only 40 per cent capacity utilisation that would bring it to a halt.

Reliance Industries Limited enters into pact with 3 power discoms

December 1, 2008. Reliance Industries Ltd. (RIL) has entered into an agreement to sell solar energy to three three power companies of Rajasthan — Jaipur Discom, Ajmer Discom and Jodhpur Discom. RIL is setting up a 5 MW solar power generation plant at the Khimsar village in Nagaur district. As per the Jaipur Discom, the agreement is first of its kind to tap the solar energy for the benefit of consumers in the state.

According to the agreement, RIL will get Rs 15.78 a unit. The power purchase rate would be Rs 3.67 for 10 years while Indian Renewable Energy Development Agency (IREDA) will pay Rs 11.33 a unit as per the directives of Renewable Energy Regulatory Commission (RERC) to promote solar green energy. Besides, the discoms will pay 78 paise a unit to the power generation company. The tariff and incentives will be applicable only if the plant is commissioned by December 2009. Electricity generation from solar energy is prohibitively expensive.

Tatas to invest more in wind power sector

November 30, 2008. Aiming at reducing carbon emission, the Tata Power will make additional investments in the wind power sector to take its production capacity from the present 200 MW to 500 MW by 2011. It has started to concentrate more renewable energy and is planning to increase its production capacity from the present 14 percent to 25 percent in the next couple of years.

The company was planning to reduce its dependency on coal for power generation and to concentrate more on solar, hydro-carbon and gas, considering the negative aspects of global warming. The Tata group was already exporting electric version of the Indica car to Norway and the company was seriously considering to launch it in the country if the government provided financial subsidy to it. The car, which is being exported to Norway, will cost around Rs 25 lakh in India if it is not subsidised.

India’s green spending could reach $150 bn by ’17

November 28, 2008. Biofuels, wind and clean coal are among the top climate change investment themes for India, global bank HSBC says in a report, highlighting sectors expected to attract spending of $150 bn between 2008 and 2017. The report, "India's climate investment opportunities revealed", also named seven companies given an overweight rating as likely to benefit from green speeding.

The report said India's National Action Plan on Climate Change, launched in June, plus a range of existing policies, had kick-started investment in climate-friendly projects. India is the world's fourth largest emitter of greenhouse gases after China, the United States and Russia. Per capita emissions are about two tonnes, compared with 20 tonnes in the United States and 28 in Australia. The report forecast total investment of 7.6 trillion rupees (about $150 bn) in 11 themes, with clean coal technology top of the list at 1.7 trillion rupees, followed by wind at 1.34 trillion and biofuels at 1.47 trillion.

It estimated the total annual emissions saving of these investments at 480 mt of carbon dioxide from financial year 2018 onwards. But the report also highlighted risks from the global financial crisis to investment, which it said had thrown into question the durability of climate change as an investment theme. Although power capacity increased only 21,180 MW under the last Five Year Plan, this is set to grow four-fold in the current planning period to more than 80,000 MW.

India has the fourth-highest installed wind power capacity in the world. Despite strong annual growth, HSBC estimated installed capacity by March 31 this year amounted to just 6.2 percent of India's gross wind potential of 45,000 MW. Biofuels also had large potential. The shift from 5 percent blending to 10 percent across the country will require an additional 600 million litres of ethanol, thus benefiting sugar companies, as well as biofuel equipment manufacturers and technology suppliers.

The report also pointed to the government's backing of more efficient coal generation, such as supercritical and ultra supercritical technologies that make use of higher pressures and temperatures to boost efficiency and cut emissions. Assuming a benchmark cost of 45 million rupees per MW, the report estimated a capital investment of 1.7 trillion rupees in supercritical technology over FY 2008-17. These investments are likely to result in annual emission savings of 28 mt from 2017. 

TVA issues RFP for renewable, clean energy power supply

December 2, 2008. The Tennessee Valley Authority is requesting proposals to supply up to 2,000 MW of power generation from renewable and clean energy sources to TVA by June 1, 2011. Up to 1,000 MW of generation would be delivered to TVA by June 1, 2009, according to the Renewable Energy and/or Clean Energy Resources request.

The amount would increase to a maximum of 1,500 MW a year later and to 2,000 megawatts by June 1, 2011. TVA is targeting individual companies capable of producing at least 1 MW of electricity from renewable or clean energy resources and is interested in proposals that would provide the power supply from 1 to 20 years.

TVA's Environmental Policy approved by the TVA Board forecasts that more than 50 percent of total power generation will come from zero or low carbon-emitting sources such as nuclear and renewable energy by 2020. Renewable energy generation technologies that will be considered include solar, wind, hydropower, ocean, tidal, geothermal, biomass and other biologically derived fuels.

Clean energy generation technologies include combined heat and power, waste heat recovery and other low-carbon emitting resources. TVA will contract for the output of renewable and clean energy generation through power purchase agreements. In addition, as TVA evaluates its renewable and clean energy portfolio, another RFP is being issued to allow others to partner with TVA on the continued operation, study and use of TVA's original three wind turbines on Buffalo Mountain.

TVA installed the wind turbines in 2001 and established the first successful wind farm in the Southeast. Since then, 15 additional wind turbines have been installed on Buffalo Mountain, which TVA supported through a power purchase agreement. TVA is the nation's largest public power provider and is completely self-financing. TVA provides power to large industries and 158 power distributors that serve approximately 9 million consumers in seven southeastern states.

Areva to build bioenergy power plants in Germany and Belgium

December 1, 2008. Evonik New Energies, a utility company, has awarded Areva the construction contract for a biogas power plant in Kirchwalsede, Germany. Up to 30,000 tons of vegetable and animal residues will be used every year in a horizontal fermenter and a post-fermenter for the biogas production.

The biogas combined heat-and-power facility will generate in total 1.43 MWe of electricity. In parallel, the heat produced will be used to power the fermenters and dry the digestates to produce fertilizer. Construction of the plant will be finalized in 2010. Intrinergy has selected a consortium comprising Areva and KEM, a Danish supplier of biomass technology, to supply a turnkey cogeneration biomass plant and wood pellet manufacturing facility in Belgium. The power plant will produce up to 4.5 MW of renewable electricity for the local grid, and approximately 8 MW of process steam for a belt drier at the pellet manufacturing facility.

Solar and wind power generating facilities installed at Nakaze Plant

December 1, 2008. Yamaha Motor Co., Ltd. has installed both solar and wind powered generating systems at its Nakaze Plant in Japan as part of initiatives to employ alternative energy sources to replace petroleum fuels. As part of the Yamaha Motor manufacturing system, the Nakaze Plant engages in the shaping and painting of external parts such as cowling for its motorcycles.

The newly installed solar and wind power generating systems went into operation today at the factory. This is the first case of simultaneous operation of solar and wind power generation at a Yamaha Motor group factory. The combined annual generating capacity of the two systems is approximately 26,000 kwh and they are expected to enable a reduction of CO2 emissions equivalent to approximately 18 tons.

According to Yamaha Motor, the electricity generated by these two systems will be used for the lighting and air-conditioning system for the offices of the factory’s employee welfare building. The solar power generation system has been installed as a joint research project with the independent public sector organization New Energy and Industrial Technology Development Organization (NEDO) and it is the seventh system to be installed by Yamaha Motor.

Under the joint agreement, Yamaha Motor will supply data to NEDO on the system’s operation for the first four years. The system adopts a new format modular type design with a larger annual generating capacity than conventional systems of the same rated output and is also has a smaller environmental footprint in that it is manufactured by a process that results in lower CO2 emissions. The vertical type wind power generation system is the first of its type to be adopted by Yamaha Motor.

This type is quieter than a propeller-fitted windmill type, which makes it a more community-friendly system from the standpoint of neighbouring residents in the factory area. Yamaha Motor has pursued numerous means to reduce the environmental impact of its manufacturing operations, such as the installation of cogeneration systems and solar generation and changing from petroleum to natural gas as the fuel for its Aluminium melting ovens.

Under the corporate environmental plan, Yamaha Motor has set a goal of reducing CO2 emissions in its manufacturing operations by 12.5% compared to the 1990 level of 99,853 tons by the year 2010. That goal has already been achieved in 2007, when the reduction versus the 1990 level reached 14.4%. The company will continue to actively pursue environmental initiative including the switch to alternative fuels to replace petroleum and adopting new forms of energy.

 

 

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