MonitorsPublished on Jan 04, 2005
Energy News Monitor I Volume II, Issue 29
Biodiesel as Diesel Substitute: Assessing the Potential in Light of India’s Air Quality Goals & Energy Security Imperatives Part- II

4.0. Study Set-up


n this study, only relevant aspects of biodiesel emissions and India’s air quality scenario have been considered for critical review. Other aspects like driveability, compatibility, storage, distribution, socio-economic viability, etc. have not been assessed. Only the emissions aspects have been taken up assuming biodiesel to have favorably passed all the above criteria[1] in this case. The ambient air quality data for various Indian cities are actual monitoring data from CPCB.

Fig-1[2]: Average Emissions Profile for Biodiesel Blends

Biodiesel can be used in a conventional diesel engine in varying proportions ranging from as high as neat (100%) biodiesel to as low as 0-5% mix. Exhaust emissions and other factors are necessarily influenced by the quantity or proportion of biodiesel blended with petrodiesel in the fuel mix. It is established that with the increase in quantity (%) of biodiesel, NOx emissions tend to increase and this situation calls for careful selection of percentage of biodiesel to be blended. In our case we have considered 20% biodiesel blend called B20, (i.e. a fuel mixture containing 20% biodiesel and 80% petrodiesel). This selection is based on figure-1[3] above which shows average representative emissions profile under varying percentages of biodiesel blends. Various national & international studies and experiments found B20 to be the best mix emitting substantially lower PM, CO, HC and other non-regulated pollutants along with lesser, comparable or marginally higher but statistically insignificant NOx emissions. Moreover, B20 blend is also preferable as this essentially doesn’t call for any modification or alteration in the existing conventional diesel engine. Thus the biodiesel fuel referred in this paper is basically B20 meant for use as a diesel substitute in India.

4.1. Emissions & Environmental Aspects of Biodiesel (B20)

Biodiesel is a renewable fuel that can be produced from vegetable oils, animal fats, used cooking oil, and waste from the pulp and paper industry. A good number of studies and tests confirmed that biodiesel is not associated to any health and environmental hazards in both life cycle (LCA) stages as well its used phase as automotive fuel. Biodiesel, due to its biodegradable nature and essentially having no sulfur and aromatic contents, offers promise to reduce particulate and toxic emissions from vehicle exhausts and throughout its life cycle it is found to emit comparatively lower greenhouse emissions.

Table-1[4]: Comparative Life Cycle (LCA) Emissions







Fertiliser Production




Fertiliser Application




Agricultural Machinery*




Oil Production


Vehicle Operation


Processing Straw**



Processing Gas




Vehicle Operation




Total (Straw Processing)



Total (Gas Processing)


*Assumed mineral diesel oil used.

** Emission of straw include those from transporting straw

Table-1 above gives the comparative greenhouse emissions from biodiesel and petrodiesel under different stages of their Life-Cycle. It is clear that overall greenhouse emission potential is quite lesser compared to that of petrodiesel. Many studies also show that an equivalent CO2 emission for biodiesel is marginally more or similar to that of fossil diesel in the pre-use production stage. However, this should not be separately cited undermining the substantial greenhouse emissions benefits of biodiesel in the complete Life-Cycle assessment, which is the most accepted way of assessing greenhouse emission potential for any energy source.

Table-2[5]: Comparative Exhaust Emissions- Petrodiesel & Biodiesel (B20)


Engine Type


Emissions in (g/bhp-hr)





ORTECH, 1995

Cummins N-1487 MUI











% Change





Stotler 1995 Cummins L

1087 MUI











% Change





Marshall, 1995

Cummins L-10-92











% Change






 et al

1996 DDC Series 60-91 DDECH











% Change






Cummins B 5.9/1996











% Change






DDC Series 60 260 KW 1997











% Change





Mahindra & Mahindra












% Change







% Change






Table-2 given above shows comparative vehicle exhaust emissions test results from different experiments carried out internationally. All the studies were carried out with available conventional diesel fuel (for USA-D2) and B20 soybean or plant based biodiesel except the Mahindra & Mahandri test which used Indian conventional diesel. The table clearly indicates reductions in emissions of PM, CO and HC and marginal increment in NOx emissions. Results and trends of the studies cited in the table and most other international trials predominantly indicate reductions of PM, CO, HC and other unregulated emissions with biodiesel. However, NOx emission trends with biodiesel, especially B20 indicate mixed trends. It is established that with increasing percentage of biodiesel in the fuel mix NOx emission tend to increase.

Many of the experiments give confidence that NOx emission can be controlled easily and at least kept similar, if not lower than the original levels with B20 biodiesel fuel. This situation also favors B20 when compared to other higher biodiesel blended fuels subject to minor adjustments. The vehicles used in various studies as reported in Table-2 fairly represent on-road diesel vehicles mix and vintage and their average emissions may directionally give a measure of biodiesel’s impacts on different emissions parameters. As per table-2, NOx emission with biodiesel is found to increase in the range of (0% to 13%) with an average increment of 2.62% compared to conventional diesel. Similarly, B20 reduces PM emission in the range of (9.4% to 38%) with an average reduction of 17.6%, CO emission reduction in the range of (3.6% to 22.4%) with an average reduction of 15.4% and HC emission with B20 also reduces in the range of (18% to 57%) with an average reduction of 22.6%. It may be noted that in all the trials referred in the above table the B20 biodiesel was basically derived from plant feedstocks and also results of other tests including some Indian tests are found to fall in the ranges of percentage emission changes as observed for the tests in the table. These ranges and averages in emissions changes for various pollutants being fairly representative have been considered for assessing the biodiesel impacts.

Table-3: Comparative Toxics Emissions[6]

Toxics (Gaseous PAH


US Petrodiesel

50% Biodiesel













Source: National Biodiesel Board/USA

… to be continued

Views are personal

Rajesh Debroy, [email protected]

Regional cooperation for Energy Security in Asia: Some Reflections

Part - II

Dr. Samir Ranjan Pradhan§

The potential for growth in oil and natural gas use can be illustrated by developmental comparisons. China’s per capita oil consumption is nearly 22 times less than that of the United States and 13 times less than that of South Korea. Per capita electricity use in China is about 5 percent of the OECD average; in India, it is just over 3 percent. Still the level of energy efficiency is less and since the economies like India and China are starting from a lower base, there is every likelihood of the consumption growth of energy moving upwards. Table 1.2 shows the oil demand and supply balance in the Asian region, as cited by APERC.

Table 1.2: Oil Demand and supply balance in Asia (mb/d)





Net Imports

























Chinese Taipei





























Source: APERC 1998.

While Asian oil consumption is expected to increase from 6 to 12 mb/d in the coming decade, regional supplies are not expected to grow corresponding to the consumption growth. The IEA forecasts Asian oil production to fall to 6.4 mb/d by 2010 from the current level of 7.92 mb/s (2005). The relatively lower reserve base, lack of discovery, though, there are some important discovery of natural gas fields, and pervasive resource scarcity has led many major consuming countries such as Japan, China, Korea and India to bring oil import policies to greater prominence among national strategic concerns. These apprehensions amidst global oil market developments have tempted these Asian consumers to aggressively pursue “go out strategy” through their national oil companies in producing regions through equity oil deals and joint ventures. These efforts in a sense have raised the stakes of stability in the producing regions having multidimensional implications, thereby, centering the regional energy security perspective in the global mainstream. This has led to the emergence of what can be termed as “energy security dilemma”[7], which commends to be minutely analyzed in order to devise enabling policy directions.

Issues and Implications

Countries in Asia are overwhelmingly dependent on oil imports and there are clear trends of the increasing imports of natural gas in the coming years. The direction of Asia’s oil imports shows substantial dependence on one region that is Middle East, though in recent years African oil imports is on the rise. There are certain crucial issues with regards to oil and gas imports having considerable bearing on the region’s energy security. The various issues along with their bearing on the regional energy security can be explained as below:

1.        Region-specificity oil import portfolio

Unlike the US and Europe whose oil import are sourced from diverse regions such as, South America, the Middle East, Africa, Europe and Russia, where arbitrage provides an economic window for traders; regional oil import in Asia is substantially concentrated in a single producing region, i.e., the Gulf region. This is partly due to geographical location and partly due to slower development of regional oil markets in Asia. In 2004, nearly 70% or 12 mb/d of Asia’s oil imports were sourced from the Gulf region, with only a small portion (2mb/d) from Africa. As per IEA forecasts to the year 2030 the volume of traded oil from the Gulf to Asia will increase to 28 mb/d, with some limited diversity of supply from Eastern Russia/FSU into North East Asia. This implies that as a consequence of higher oil imports from the Gulf, Asian countries once shielded geographically from the turbulence of the Middle East will no longer be able to leave it on the margins of their geopolitical agenda. This, in other words, envisages that there may be greater common cause in the search for regional stability. (see figure a below).

2.       Asian oil premium, lack of regional marker crude and risk avoidance

Another factor impinging on the region’s energy security is the phenomenon called ‘Asian oil premium’. Asian oil premium refers to ‘the margin above the actual market price of Dubai crude (crude oil exports from the Middle East) that the Asian oil importers usually pay in comparison to their counter parts in America or Europe’.

“Asian premium costs India alone $500 million per year, and costs the region as a whole an extra $5 to $10 billion per year, depending on oil prices. This is on top of soaring international oil prices in the year 2004, which unless sharply moderated in coming months, are likely to lead to a 50% increase in India’s annual oil import bill”.

Research by the Institute of Energy Economics, Japan (IEEJ) estimated the premium at $1 per barrel during the period 1992-95 and at around $1.5 per barrel for 1992-98 and the year 2001-02. Moreover income transferred on account of the premium from the Asian countries to the Middle East exporting countries has been estimated to be to the tune of $8-10 billion. In another presentation, Ogawa has pointed out that this premium has seriously affected the emerging economies of the Asian region in several ways: (i) Premium has pervasive impact on the international competitiveness of national economies in Asia, (ii) it led to worsening refinery margins in the Asian region since the year 1999, thereby marginal flow of investments in refining and larger imports of products (iii) it is not limited to oil only, rather exposed to other energy forms and the resultant higher prices of these energy, such as LNG, LPG contract pricing.

The proximate factors for the Asian Premium are determined and influenced by the structural distortions, economic, financial, technical and geopolitical tenets of the global oil and gas industry. Some of the proximate factors for the premium can be listed as follows:

Figure ‘a’: Asia and Middle East- Oil Interdependence

Source: IEEJ, 2003.

(to be continued)

Decisions in Power Sector for a Powerful India


Tata panel recommendations

·         Units with low plant load factor of 40 per cent must be sold or leased out

·         Fuel linkage must be provided to idle plants with significant capacity

·         Shortlist investors to put up coastal plants that can operate on imported coal

Ministries’ views

·         Take over of such poorly performing power plants is in      the interest of the sector

·         Cost of alternative fuels is high, so duty waivers on LNG may be extended

·         Four sites, including two coastal, identified. Bids to be invited for lowest tariff

PMO decision

·         Options like leasing, JVs and takeover must be explored

·         A note will be sent to the PMO on sales tax and customs waiver on LNG

·         A note to be submitted by power ministry to PMO within in a month



Sources of India’s Oil Imports – 2004-05


Oil Imports


% of Total


Middle East Region










Neutral Zone









Saudi Arabia









Sub Total



Other Region






















Equitorial Guiana



























Sub Total







Source: Planning Commission, Govt of India





India eyes oil deals with China

January 9, 2006. India's oil minister, Mani Shankar Aiyar, will hoping to cement energy ties with China but analysts say Beijing's supremacy in the race for foreign oilfields will limit his bargaining power. Chinese and Indian firms have competed fiercely for energy assets on offer around the world as their governments drive them to secure supplies for the import-dependent countries. Indian oil minister is of the view that competition between two of Asia's largest oil consumers makes assets more costly and helps Western companies sell ageing oilfields at a premium. He wants India and China to bid jointly for some assets and compete when they consider strategic interests more important. India's diplomatic efforts helped China National Petroleum Corp. and India's ONGC jointly win an auction for PetroCanada's Syrian fields. Encouraged by this, energy firms from both countries will sign deals for joint business initiatives and the two governments will seal an agreement for energy cooperation during Aiyar's visit to China.

It was also possible the energy-hungry neighbours might be able to win joint contracts in countries where governments were wary of one of the two regional heavyweights gaining too strong a sway over a strategic industry like energy. In its latest move, Chinese top offshore producer CNOOC Ltd. is buying a stake in a Nigerian oil and gas field for about $2 bn (Rs 88 bn) in what would be the company's largest-ever overseas acquisition. So far Indian and Chinese firms have been partners only in places where Western rivals are few- first Sudan, now Syria.

India eyes oil deals with China

January 8, 2006. Gujarat State Petroleum Corporation has decided against tapping the capital market to develop India's largest gas find of 20 trillion cubic feet (TCF) in the Krishna Godavari basin. Instead, GSPC is exploring the joint venture (JV) route with international oil majors to develop the basin, which would require funds of over Rs 1,500 crore ($336 mn). The company had earlier talked about diluting up to 20 per cent stake by December 2005. GSPC has shortlisted several international oil and gas majors for equity stake and for technology partnership. These companies include Shell, ExxonMobil, British Petroleum, British Gas, ENI of Italy, Total of France and Enadarko. ONGC, GAIL India Ltd and IOCL have also envisaged interest in picking up equity stake for developing the KG basin. IOCL has even signed a memorandum of understanding for developing the basin together.

Eastern region to get first CBM by ’07

January 6, 2006. Gas consumers in the eastern region can look forward to a new energy source with the first coal bed methane (CBM) gas project slated to hit the market by January ’07. This gas will come at a competitive price of around $5-7 per mmbtu as compared to the costlier alternatives of furnace oil or coking coal. The first commercial operation of CBM gas in India is set to begin with the Great Eastern Energy Corporation (GEECL), a YK Modi group company, planning to kick off drilling operations at the Ranigarnj coalfields, West Bengal, by mid-January. The fields could have a reserve of almost 817 cubic feet of gas over a 25-year period. The company has projected an investment outlay of approximately Rs 575 crore ($130 mn) for the first 100 wells.

Assam Co hunts oil in Australia

January 5, 2006. Assam Company has entered into a MoU with the U.S.-based DMS Exploration for acquiring 33.33 per cent working interest 625 square kilometre oil and gas block in South Australia and for forming a joint venture. The company would own the entire oil block. The joint venture outfit would start the exploration activities by March 2006. The block is located at Stansbury Basin of South Australia. ACL CFO indicated that it might jointly bid with DMS for oil blocks in India under NELP 6. 

ABB to provide control and data acquisition system to ONGC

January 5, 2006. Power and automation major, ABB Ltd has bagged a turnkey order worth Rs 430 crore ($96.39 mn) to provide an enterprise wide supervisory control and data acquisition (SCADA) system for ONGC's production and drilling facilities. The project, expected to be completed by end of 2007. ABB's integrated automation solution will enable ONGC to monitor, control and manage vital data across locations and enable faster decision-making. It will also help speed up emergency response and deliver enhanced efficiency, energy savings, quality and productivity improvements. This system will enable ONGC to integrate its basins, plants, forward base and other assets to the corporate data center, facilitating 'anytime-anywhere' access to data and real-time performance management. The initiative will improve performance and efficiency of ONGC's geographically dispersed production and drilling facilities, both onshore and offshore, it added. 

IOC-OIL to acquire blk in Gabon

January 4, 2006. The IOC-OIL duo is all set to acquire a 90 per cent participating interest in an exploration block ‘Venus’ in Gabon in West African country, adjoining the British Gas-Remboue oil field. The total cost of the project is close to $1.2 bn (Rs  bn) and is the biggest investment planned jointly by the two companies so far. The initial risk money, given IOC’s and OIL’s share of 45 per cent each, would be Rs 228 crore ($51 mn). This includes the entry cost and the initial exploration cost. Considering a recovery factor of 30 per cent, which is comparable to the BG-Remboue producing field, the likely recoverable reserves are estimated to be 167 million barrels.

ONGC ties up with Hinduja Group for E&P

January 3, 2006. ONGC has tied up with the Hinduja Group for joint collaboration in O&G projects in India and overseas. Hinduja Group have signed a MoU with ONGC for joint collaboration in the O&G sector for India and overseas projects. This MoU entails synergy and growth for both sides. Analysts believe ONGC hopes to leverage Hindujas' presence in the Gulf region to pick up equity stakes in the E&P assets the region. The Cabinet Committee on Economic Affairs (CCEA) had shot down ONGC's proposal to pick up stake in a Nigerian oil and gas field on the grounds of the "risk element" involved. MoUs like the ones wit the Hindujas and the Mittals will help ONGC acquire overseas assets with reduced risk and investment.

Hindujas are also planning to source liquified natural gas (LNG) from Iran. Both Hindujas and ONGC are also planning to jointly promote, develop and invest in LNG terminals with associated power, petrochemicals, gas pipeline grid projects and related opportunities in southern India. The cost of all these projects is pegged at Rs 25,000 crore  ($5.56 bn). The Hinduja Group, through one of its group companies Ashok Leyland Project Services Ltd (ALPS) has joined hands with gas infrastructure major GAIL India Ltd for compressed natural gas projects.


Scrap price regime in petro sector: Teri

January 9, 2006. Industry think-tank The Energy and Resources Institute (Teri) has demanded an end to government diktats on pricing of petroleum products and sought subsidies on LPG and kerosene to be directly provided to consumers. According to a study on petroleum pricing by Teri, government should move to market determined prices of petrol, diesel, LPG and kerosene immediately. Subsidised LPG and kerosene can be provided to targeted consumers by giving them prepaid cards from which the subsidy amount would be deducted everytime a purchase was made. This would help check black marketing and help track pattern and extent of subsidy utilization. The study also mentioned that import parity pricing formula (used for calculating retail prices of fuel) needs to be re-visited to ensure that the Indian refining industry enjoys a rational margin that is fair to producers as well as consumers.

RIL seeks compensation for selling fuel below cost

January 9, 2006. Reliance Industries, which controls 9 per cent of the petrol and diesel retail market, has sought compensation for selling petrol and diesel below the cost price, similar to what is being extended to public sector oil marketing companies (OMCs). Private sector companies including Reliance Industries, Shell and Essar have fared poorly in the area of retailing petroleum fuels. While Essar Oil has already reduced the sales of petrol and diesel from its retail outlets, the only mutlinational oil company, Shell, which is retailing petrol and diesel at present, is also going slow with the expansion of its retail outlets. Reliance had been “unfairly” asked to extend discounts to the tune of Rs 750 crore ($170 mn) on the petrol, diesel, LPG and kerosene it sells to PSU retailers. Reliance has set up over 900 petrol stations throughout the country and commands 9 per cent of the petrol and diesel market share.

India has refining capacity of additional 30 mt: Shell Global

January 5, 2006. Shell Global, which was commissioned to do a detailed feasibility study on making India an investment destination for refiners, in particular export-oriented units, has suggested that India has the refining capacity of 30 mt over and above the existing and planned projects. Shell Global has also proposed that any scope of refinery should be linked to petrochemical production facility, which could be sold in India. Further, the refinery and petrochemical projects would require tax and fiscal concessions. Noting that India has already established itself as a net exporter of petroleum products with export earnings of over Rs 28,000 crore ($6.28 bn) in 2004-05, Indian Oil Corporation was asked by the Petroleum Ministry to prepare a detailed feasibility study aimed at promoting India as the refining hub of South Asia and South-East Asia. IOC had roped in Shell Global to undertake the study.

The Petroleum Ministry proposed to work out an action plan for the investment purposes based on the feasibility study. It is likely to prepare a Cabinet note proposing the investment plans. The estimated export of petroleum products during 2005-06 is 13.305 mt worth Rs 20,374 crore ($4.57 bn). Export earnings during the first quarter of 2005-06 amounted to Rs 8,962 crore ($2 bn). The refining capacity as of April 2005 was 127.37 million tonnes per annum (mtpa). There were plans to enhance this capacity to 141.70 mtpa by the end of the Tenth Five-Year Plan (2006-07). The total capacity addition or expansion plans of about 14.33 mt will be by the oil companies such as Bharat Petroleum Corporation Ltd, IOC, and Hindustan Petroleum Corporation Ltd put together. Apart from this, public sector oil companies have also proposed to set up four new refineries, completion of which is likely to spill over beyond the Tenth Plan. The new refineries are one each of IOC and HPCL and two of BPCL.

Transportation / Distribution / Trade

Dabhol may get PLL’s LNG

January 10, 2006. Peeved at the slow progress in sourcing of fuel for restarting the beleaguered Dabhol power plant, the government has roped in Petronet LNG to scout for LNG to fire up the 2,184 MW plant. GAIL had been unsuccessful in getting LNG for restarting the plant by June 2006. So it was decided to get Petronet on board the LNG sourcing committee. Petronet would talk to Qatar for LNG for the Dabhol plant while it will take GAIL along for negotiations with Oman and Abu Dhabi for the fuel. LNG suppliers in Australia, Malaysia, Qatar, Oman and UAE are quoting a price of about $7 per million British thermal unit (mbtu) for the gas required to fire the plant. The electricity generated at this price would be more than Rs 3 per unit.

Rasgas of Qatar, which is being courted by Petronet for supplies for the phase-I of the power plant, has offered a price of $7.5 per mbtu. North West Shelf (NWS) of Australia quoted a price of about $7 per mbtu for supply of 0.5 mt of LNG during 2006-07 and 2.3 million tonne per annum from 2008 onwards. Malaysia LNG offered 0.75 mt of LNG per annum from Egypt at an ex-ship price of $7-8 per mbtu. Oman LNG and Adgas of UAE, the original LNG suppliers to the Dabhol project, are also quoting a similar price.

Oman LNG has indicated availability of 0.6-0.8 mt LNG in 2006, 1.0-1.2 mt for 2007 and 1.6-1.8 million tonne per annum from 2008 onwards. Adgas has offered 0.7 to 1.3 mt LNG per annum from 2006 onwards. Ratnagiri Gas needs 0.64 million tonne per annum of LNG in 2006, which would go upto 2.83 mmtpa in 2007 and 5 mmtpa from 2008 onwards. The power plant (740 MW phase-I and 1,444 MW phase-II) requires 2.1 mmtpa and the balance 2.9 mmtpa would be used for merchant sale. Qatar has indicated an availability of five spot cargoes equivalent to 0.3 mmtpa in 2006 and potentially 0.75 mmtpa in 2007 and 2008 but negotiations are struck at price of gas.

Panna Mukta Tapti seeks to be free of APM burden

January 8, 2006. The Panna Mukta Tapti, joint venture between ONGC, British Gas and Reliance, will approach the Union Petroleum and Natural Gas Ministry, Mani Shankar Aiyar, seeking release of 6 million standard cubic metres (mmscmd) of gas for direct marketing in the next fiscal. PMT now supplies 6 mmscmd of gas out of a total production of 10.8 mmscmd to GAIL for supplies to the power and fertiliser sectors in North India, at an administered price of $3.86 per million metric tonne British thermal unit (mmbtu). For the rest of the output, which was released for direct marketing last year, the joint venture gets a minimum of $4.08 per mmbtu from Gujarat State Petroleum Corporation Ltd (GSPCL), Gujarat Gas, Indian Petrochemical Corporation Ltd and others. According to rough calculations, if PMT is allowed to sell its entire production at market prices, its profits will increase by approximately by Rs10 crore ($2.24 mn) in 2006-07.

Gail to pay global rates for some ONGC products

January 5, 2006. In a major development that is likely to impact their bottomlines, the ministry of petroleum and natural gas has cleared a gas sales agreement (GSA) with a ‘take or pay’ clause between the country’s largest gas producer ONGC and gas marketing company Gail. The agreement, expected to be signed soon, envisages international prices to be paid to ONGC for some kinds of gas. The pricing of these gas fractions (called C2, C3, C4 and C5 in oil industry jargon) has been hotly contested between the two companies. They have so far been dealing with each other on the basis of an MoU that has lapsed several years ago. ONGC’s contention has been that the ‘rich and lean’ gas should be priced differently. Gail uses the rich gas purchased from ONGC, as an input to manufacture petrochemicals and LPG. It has over the years refused to accept any change in pricing, since it would erode its margins. However, the ministry of petroleum has now ruled that the price of the fractions would be increased to market levels in steps of 15 per cent every six months, with a final price increase of 25 per cent. The price will be completely market determined by the end of three years. In a related development, Gail will be allowed a marketing margin on the gas. Gail currently makes most of its revenues as transportation tariff for the gas through its pipeline network, that is the biggest in the country.

Shell denies Hazira sale plan

January 5, 2006. Royal Dutch/Shell, world's third largest oil and gas firm, said its $600 mn (Rs 26.77 bn) Hazira liquefied natural gas import terminal in Gujarat was fully operational and the company had no plans to sell it off. Shell, which began operating India's second LNG terminal in April 2005, has till now imported only 3 cargoes of LNG as it was unable to find customers willing to pay market price of $8-9 per million British thermal unit (mBtu). The market price was roughly double the cost at which Petronet LNG Ltd, India's largest LNG importer, was selling regasified LNG from its Dahej terminal in Gujarat.

GSPC firm on ending Shell pact

January 4, 2006. The future of Shell’s LNG business in India was further thrown into uncertainty, with the Gujarat State Petroleum Corporation, Shell’s first and only customer for LNG from its Hazira project, deciding not to renew its gas sales agreement with the company. GSPC’s 7-month agreement with Shell to source 0.7 MMSCMD (a per day measure) of gas ended in December 2005. Shell was asking almost three times higher prices over $9 per million metric British thermal units (mmbtu) for LNG, while it was supplying LNG at $3.7 mmbtu to GSPC a per the GSA. GSPC’s decision may cause shortage of around 0.7 million cubic meters per day of natural gas for Gujarat industries.

Policy / Performance

RIL in largest offshore loan deal of $1.5 bn

January 10, 2006. Reliance Industries plans to raise $1.5 bn (Rs 72.50 bn) offshore loan, the biggest ever by an Indian corporation. Basis Points, a Reuters subsidiary, which specialises in providing information on overseas debt plans of corporations, said one of the tranches of the two-part loan was expected to have a door-to-door tenor of 10 years, the longest ever by an Indian corporate. The entire loan would be priced at about 135 basis points over Libor (London Inter Bank Offered Rate). The company was in talks with at least 15 banks for underwriting of nearly $300 mn (Rs 13.25 bn). Reliance Industries said half of the investment would go for doubling of petroleum capacity at Jamnagnagar. It will also begin full-year gas production from the Krishna-Godavari basin from 2009-10 after spending Rs 17,000 crore ($3.85 bn) in upstream oil and gas over the next few years. Reliance will also invest Rs 2,500 crore ($566 mn) in building a new 280,000 tonne-per-year polypropylene plant. 

Reliance Industries Ltd has floated global tenders for developing its deep water gas discoveries in KG D6 block of Krishna Godavari basin on the Eastern Cost of the country. It has planned for setting up an onshore gas terminal near Gadimoga village in Kakinada in Andhra Pradesh. The KG D6 field operations would be controlled from the gas terminal. The company has invited bids on behalf of its co-ventures like Niko Resources for the blocks acquired under National Exploration Licensing Policy I to IV and exploration rounds CBM 1 and 2. The bids include design and supplying of gas pipe and generators, distribution and control system besides supply of fuel, lubricants, pumps, air compressors, oil well cement as well as activities related to drilling and construction of Mobile (Floating) Production facility (MPF). RIL has already signed an Expression of Interest with country's biggest power producer NTPC for supply of around 132 Trillion British Thermal Units of gas from 2007 to the state-owned power major's plants in Kawas and Gandhar in Gujarat. However, RIL has not yet signed the Gas Sales and Purchase Agreement in this regard.

CCEA for financing strategic oil storage

January 7, 2006. The Cabinet Committee on Economic Affairs approved the proposal to set up 5 mt of strategic crude oil reserves at an estimated cost of Rs 11,267 crore ($2.52 bn) through Oil Industry Development Board (OIDB) cess. The facilities would to be built in Mangalore and Vizag by Indian Strategic Petroleum Reserves Ltd, a subsidiary of the OIDB, over 9 years. ISPRL will also manage the strategic crude oil storages. Operating the stockpile will cost about Rs 90 crore ($20.15 mn) per annum. The project would enhance the country’s energy security, particularly during short-term oil disruptions.  IOC was to float a special purpose vehicle - ISPRL for building the reserves but the CCEA has now decided that equity held by IOC be transferred to OIDB. The project would be funded by OIDB through imposition of new imposts on crude. A cess on crude or an additional 2 per cent import duty on crude or a combination of both of these measures is being considered to mop up the funds for building the storage facility.

Petromin to legalise oil cos' subsidy-sharing

January 4, 2006. The petroleum ministry is considering the option of issuing a legal notification to formalise the subsidy-sharing formula in the oil sector by which companies such as ONGC and Gail India are allowed to offer discounts to oil marketing companies. Tax authorities have been objecting to the discounts as the companies have shown reduced earnings and lower taxes thereof. Adhoc subsidy-sharing had also attracted the ire of FIIs and other institutional investors which had questioned the company about giving discounts on crude prices. The petroleum ministry is likely to take up the matter with the finance ministry to issue a formal legal notification on these lines. It remains to be seen whether this would become a policy directive on subsidies in the oil sector. Revenue officials have been demanding taxes to be paid on the invoice value of the crude sales instead of the discounted price at which ONGC has been selling crude.

Petromin in favour of regulatory mechanism

January 3, 2006. The petroleum ministry has strongly emphasised the need for a proper regulatory mechanism to be put in place to ensure a systematic development of the Indian gas market in a cost-effective, efficient, safe and competitive manner. The ministry, in its note said that it is in the midst of bringing out a gas pipeline policy to facilitate the growth of natural gas sector, which is dependent on the development of transmission pipeline infrastructure linking various gas supply sources to existing and emerging markets. The proposed policy guidelines aim to provide a framework for future growth of pipeline infrastructure with a view to eventually evolving a nationwide gas grid. The policy also aims to encourage investments in the development of pipeline infrastructure, from both the public and private sectors in a bid to provide a competitive environment and protect consumers’ interests. The ministry said that the Tenth Plan outlay for the oil and gas sector has been fixed at Rs 1.03 trillion. The exploration programmes account for over 50 per cent of the Tenth Plan outlay. The annual plan outlay for the ministry has been finalised at Rs 25,000 crore ($5.56 bn) as against revised estimates of 2003-04 at Rs 24,393.22 crore ($5.43 bn). According to the ministry, a plan outlay of Rs 30,984.07 crore ($6.89 bn) has been projected for the current fiscal which is under finalisation, in consultation with the Planning Commission.



OSEL to enter hydel power

January 9, 2006. The Delhi-based Oriental Structural Engineers Ltd (OSEL), a part of group Bakshi Enterprises, involved in road construction, will diversify into hydro-power projects. It has bid for a hydel power project in Himachal Pradesh. The company has set aside about Rs 150 crore ($33.93 mn) as equity investment in its diversification programmes during 2005-06. For hydroelectric projects, OSE would tie up with a more experienced company. The hydel project in Himachal project that the company is eyeing is to generate 7 million units of electricity with a cost of Rs 50 crore ($11.31 mn). The company plans to invest about Rs 20 crore ($4.52 mn) in the project.

28 hydel projects on the block in HP

January 9, 2006. Himachal Pradesh government has invited bids from public and private firms for developing 28 hydel-electric power projects with a total capacity of 4,000 MW. The state government has also sought applications for self-identified projects ranging from less than 5 MW to 100 MW and above on a build-own-operate-transfer basis. The HPSEB has put on the block all the potential projects identified in the state so far. The state has a total potential of about 21,000 MW in the hydel sector. Of this, projects totalling 6,067 MW are already running, while projects totalling 7,600 MW have been allotted. With the allotment of these 43 projects by June this year, Himachal Pradesh would complete the process for all its identified power potential. The state government has reserved the right to take up to 49 per cent equity in all the projects above, a condition which some of the companies including Reliance are understood to have opposed during the first round. 

Power grew at 4 pc in CY’05

January 9, 2006. Power generation during calendar year 2005 registered a paltry 4 per cent growth, primarily on account of shortage of gas/liquefied natural gas. Had this gas been available, 26 billion units (bu) of electricity would have been generated, and the growth rate would have been an impressive 8.4 per cent in generation alone. According to the power ministry’s internal report, total power generation was recorded at 605.92 bu, comprising thermal (490.84 bu), hydro (99.07 bu) and nuclear (17.69 bu). Gas-based projects are largely situated in Maharashtra, Gujarat and Karnataka, and they are run by state utilities, unbundled entities of state electricity boards, NTPC and private sector companies. These power plants are compelled to operate at under capacity due to non- availability of gas/LNG. In Maharashtra alone, MahaGenco’s gas-based plant situated at Uran, near Mumbai is able to generate around 400 MW (a loss of 450 MW). Similarly, NTPC’s plants situated at Kawas and Gandhar in Gujarat have to use naphtha as primary fuel due to gas non-availability. These gas-based projects would have to wait till February 2007 as GAIL India’s Uran-Dahej pipeline would be complete by that time, against its original deadline of June 2006. However, according to the power ministry the transmission sector has grown as peer its projections. With the completion of Raipur-Raurkela (500 MW) and Gazuwaka link (500 MW), the inter-regional capacity of 1,000 MW was added during the year.

Hindujas to revive Vizag power project

January 8, 2006. The Hinduja Group is all set to revive its 1,040 MW, coal-fired, power plant project in Visakhapatnam. The power project will be executed through the Hyderabad-based Gulf Oil Corporation. The project foundation stone was laid down in August 1994.

AP mulls setting up SPV for mega power projects

January 4, 2006. The Andhra Pradesh has directed the APGENCO (Generation Corporation) to consider the possibility of creating a special purpose vehicle (SPV) to facilitate the setting up of two mega power projects to meet the increasing demand for power in the State. The APGENCO has to set up a 2100-MW gas-based combined cycle power plant near Hyderabad and 2x800 MW super critical plant at Krishnapatnam near Nellore. The multi-stage Krishnapatnam project could potentially be increased to 4000 MW. The state wanted the project to be commissioned by June 2008. This assumes importance given the projections of major gas find in the Krishna Godavari basin by ONGC, Reliance, among others. The Andhra Pradesh Electricity Regulatory Commission, has also approved reduction in the industrial tariff by about 14 paise per unit for next fiscal. The tariff for commercial users also would be reduced. The AP Transco wanted reduced rates for these two categories to wean them away from captive generation. Any hike in the rate would force them to make purchases from private suppliers.

4 pvt power projects to start by 2010: MP govt

January 4, 2006. The Madhya Pradesh government assured that a few private power projects, of which the even the formal proposal had not been received, would be completed in 4 years. Projects that would be completed by 2009-10—the 360-MW gas-based project by Chennai firm Aban Lloyd, the 400-MW Neyveli Lignite project, the 400-MW Maheshwar power project, and the 300-MW Lanco Amarkantak project. Therefore, the demand-supply gap of 2,168 MW (the existing power generation is at 4,120 MW and the demand is 6,400 MW) will be bridged by 2008-09. The state government would add 517 MW in 2005-06, 1,235 MW in 2006-07, 1,788 MW in 2007-08, and 721 MW in 2008-09. Further, 90 MW will be available through the Tarapur Atomic Power station.

Demand for power project in Tripura

January 4, 2006. The North Eastern Electrical Power Corporation (NEEPCO) Employees Forum has requested state government of Tripura to intervene for setting up of the 280 MW gas-based thermal power project at Monarchak in West Tripura district. The central government has scrapped the proposed project at Monarchak though a sum of Rs 45 crore ($10.06 mn) had already been spent. The Centre had cancelled the project on the grounds that they had already cleared a 750 MW gas-based thermal project of ONGC.


Transmission / Distribution / Trade

Northern Grid to go high-tech

January 9, 2006. The Northern Grid operators led by Power Grid Corporation of India Ltd (PGCIL) are planning to go hi-tech by deploying helicopters to clean power lines and insulators to prevent possible tripping of lines due to a combination of heavy fog and pollution in the winter months. PGCIL proposing to recover the cost of procuring the helicopters through its tariff to the grid constituents, which could result in higher transmission tariffs for the state electricity boards (SEBs), translating into increased tariffs for the retail consumers. A committee with members from the CEA, PGCIL and Uttar Pradesh Power Corporation Ltd (UPPCL) has been formed to examine the scheme and submit a detailed feasibility report within a month.

Delhi to source more power from NTPC

January 7, 2006. The Delhi government has decided to source 1000 MW of power from the NTPC’s Lara plant in Chattisgarh. The NTPC will supply power from its 4000 MW pit-head power station to be set up at Lara in Chattisgarh. From this station, NTPC has decided to supply 1000 MW to each - Punjab, Haryana and Delhi. Besides this, the Delhi government will also sign an MoU with NTPC for the expansion of Dadri thermal power station. Through this MoU NTPC would transfer 90 per cent power to Delhi and the rest to its home state. Delhi’s power demand will cross 7000 MW by 2010 end. Due to environmental constraints, there is no scope for coal - based power projects in the Capital. Also there is a shortage of gas to meet the demand of existing as well as the upcoming power gas-based power projects. Therefore setting up of a pit head power station is the best option. Delhi Electricity Regulatory Commission has been assigned the job of negotiating the mode of payment between the Delhi government and NTPC.

M`shtra utility to come hard on power theft

January 4, 2006. The Maharashtra Electricity Distribution Company (Mahadiscom) plans to use automated reading meters (ARMs) to check the tampering of electricity meters. It plans to stop meter manipulation throughout the state by 2006 end. Once the meters are installed, the state may see a flow of additional revenue of Rs 200 crore ($44.7 mn). The meters will be equipped with GSM-based modem through an optical port. The modem will store the data which could be accessed anytime from the central control room. In case of tampering, three SMSs will be automatically generated and sent to the concerned circle, vigilance office and the head office. Thus the erring consumer will be caught. The company plans to connect 20,000 meters with the modems in the first phase by the year end. The project, which is yet to get the Maharashtra Electricity Regulatory Commission (Merc) nod, is expected to start by February. The first phase will require an investment of Rs 40 crore ($8.94 mn). The central control room for the system has not yet been finalised. The system requires the latest softwares, hardwares, high quality servers and 20,000 modems (one modem for each meter). New Delhi Power Ltd (NDPL) has already implemented the project by connecting 16,000 meters with the modems in the HT section and is gaining a revenue of Rs 10 crore ($2.24 mn). 

Policy / Performance

IFC to invest $0.6 mn in energy conservation equipment

January 10, 2006. The International Finance Corporation, the private sector arm of the World Bank, is planning a $600,000 (Rs 1.77 bn) equity investment in a Bangalore-based TurboTech Precision Engineering Private Ltd to help it expand production of energy efficient turbines. This is in line to respond to increasing demands of the global market for energy conservation equipment. TurboTech designs and manufactures small, high efficiency gas and steam turbines for cogeneration applications. IFC finances private sector investments in the developing world, mobilises capital in the international financial markets, helps clients improve social and environmental sustainability, and provides technical assistance and advice to governments and businesses.

Package deal for 4 mega power projects

January 10, 2006. The Centre is in the process of setting up four special purpose vehicles (SPVs) to pilot four mega thermal power projects with initial capacities of 800 MW each. These SPVs—in consultation with commercial banks and financial institutions—will prepare the project reports, sign power purchase agreements (PPAs) with respective state governments where the projects will be located, establish coal linkages, and put in place environment clearances before selling the projects to independent power producers (IPPs) through an international bidding process. In other words, the prospective buyers will get a package deal with all possible clearances and PPAs in place. This is the first instance of the central government negotiating for PPAs and other relevant clearances for power projects to be managed by private players. The Cabinet has already cleared the proposal. The government is planning to set up two of the projects at Champa (Chhattisgarh) and Singaroli (Madhya Pradesh). The other two locations could be Karwar in Karnataka and Surat in Gujarat. The government is also looking at Maharashtra and Andhra Pradesh. The projects will be set up at coal pit-heads and along the coastline. The government has already initiated talks with the coal ministry to tie up fuel linkages. The mega power projects will help the country reach the targeted 650,000 MW of installed capacity by the 14th Plan (2026-27). The power ministry has been looking at a generation growth of 8 per cent per annum to reach this target. The 11th Plan is expected to generate 60,000 MW of additional power while the 10th Plan will add 35,000 MW against the targeted 40,000 MW. The shortfall is expected to be bridged by expanding and bringing in the captive generation capacity in the country into the power grid.

Nashik villages benefit from power conservation plan

January 9, 2006. Maharashtra State Electricity Distribution Company’s (MSEDCL) Akshay Prakash Yojana, a programme to conserve electricity in rural areas, seems to be paying off. The villages adopting the scheme were asked to switch off three-phase power supply during peak hours and not to use illegal connections. This has resulted in power supply for 23 hours to around 1,300 villages. Among these, around 586 villages are from the Nashik district. The district suffers a deficit of 3,200 MW, which is around 25 per cent of the total power deficit. At present, the demand for power in the state is at 13,500 MW, and suffers a deficit of 9,500 MW. According to MSEDCL, the daily load in Nashik district has come down by 80 MW during day time and 180 MW during peak hours. As part of the programme, consumers have been advised not to use heavy electrical appliances during peak hours. Up to 25 per cent of power can be saved through self-control such as not using agricultural pumps and heaters during peak hours. Power thus saved could be used to maintain continuous supply. Flour mills, workshops and other units have been advised not to operate between 6 and 10 pm. In urban areas, co-operative housing societies are asked not to operate water pumps during the evening peak hours. The scheme has already been implemented in Pune (urban), Ahmednagar, Kolhapur, Nashik districts. It is under consideration in Vasai and Palghar of Thane district. It has also been implemented in the Goregaon area near Pen in Raigad district.

Energy policy to boost rural electrification

January 7, 2006. The government feels that rural electrification programme is likely to boost after the finalisation of the draft Integrated Energy Policy. The Hydrogen Energy Board is slated to lay down the road map for implementation of the national hydrogen policy. Various options for use of alternative sources of energy are being explored to complete the programme of rural electrification. Ministry of Non Conventional Energy is of the view that a targeted subsidy regime can boost the spread of use of non-conventional energy sources in rural areas, and suggested that the users of non-conventional energy should be given the same quantity of subsidy as that given to the generators of grid power for foraying into rural areas. The surplus power generated through non-conventional sources should be sold to the grid at parity prices. It suggested a coupon system for rendering subsidies to the rural poor for foodgrains as well as for energy so that dual pricing system can be phased out. However, Planning Commission did not favour the coupon system of claiming subsidy.

Plan to revive UP`s ailing power sector

January 6, 2006. Uttar Pradesh government has chalked out a tentative business plan envisaging a total investment of about Rs 51,000 crore ($11.50 bn) to provide electricity to all and turnaround the ailing power sector by 2012. The state government has estimated a total requirement of Rs 50,888 crore ($11.48 bn), including transitional funding, includes state government subsidy and grant from the Centre, of Rs 16,500 crore ($3.72 bn) and investment support of over Rs 34,000 crore ($7.67 bn) till 2011-12, by when it plans to reduce the aggregate technical and commercial (AT&C) losses to 23 per cent from 42 per cent at present. According to central government estimates, the total commercial losses of power utilities in the state have risen from Rs 2,500 crore ($564 mn) in 2001-02 to Rs 2,850 crore ($643 mn) in 2003-04. The state had the second highest commercial losses during 2003-04 in power sector after Gujarat, which posted losses of more than Rs 3,000 crore ($677 mn). An additional Rs 27,000 crore ($6.09 bn) would be needed from private players to augment generation, transmission and distribution capacities in the next 7-8 years. At present the cost of electricity supply in the state was Rs 3.93 per unit, much higher than the average tariff of Rs 2.66 per unit.

Text Box: Govt plans to invest Rs 51,000 cr to provide electricity to all, to revive the sector by 2012 
It will take Rs 17,000 cr as loans from banks, Rs 7,000 cr grant from the Centre and contribute the rest itself 
Commercial losses of power utilities in the state rose from Rs 2,500 cr in 2001-02 to Rs 2,850 cr in 2003-04 

PMO to dereserve CIL’s blocks

January 5, 2006. The Prime Minister’s Office (PMO) has supported the recommendation of the Ratan Tata-headed Investment Commission to dereserve some of the coal blocks under Coal India Ltd (CIL) in favour of Central and state government companies for mining. Of the 289 blocks reserved for CIL, 229 have been explored. Only 150 are, however, planned for production up to the end of 11th 5-year plan (2011-12) and the balance 79 are yet to be taken up for production. The de-reservation is part of the PMO’s strategy to bring more players and capital in the mining sector, even as the contentious issue of privatisation is in abeyance. Coal shortage is threatening to jack up the cost of thermal power generation, which has led the Tata-led panel to explore various options. CIL has already agreed in-principle to allot six coal blocks to NTPC for production during the 11th Plan itself. The estimated coal reserve of these blocks ranges from 200 mt to 1,900 mt.

The government’s seriousness about enhancing coal production is justified in the wake of expected shortages in coming years. According to the Planning Commission, against the total coal production of around 382.14 mt during 2004-05, the demand-supply gap would widen to 60 mt by 2011-12. The Planning Commission has assessed that for 2005-06 the total raw coal demand would be 445.65 mt whereas the total availability from indigenous source is estimated at 406.48 mt, leaving a gap of 39.17 mt.

NTPC to tap overseas power mkts

Text Box: •	Involved in power projects in Sri Lanka and Nigeria. Has already submitted offers to Nam Power, Namibia Take this
•	NTPC's technology collaborators being ABB, Germany (Anta 413 MW), ABB, Germany (Jhanor-Gandhar 648 MW), GE, USA (GEC-Alsthom), France (Kawas 645 MW), and Siemens, Germany (Dadri 817 MW)

January 5, 2006. NTPC in a serious bid to globalise its operations has formulated a comprehensive plan to pursue business opportunities in the overseas power market. NTPC is currently planning on a priority basis to set up power projects in Sri Lanka and Nigeria. This apart, the company has submitted offers against international bids to Nam Power, Namibia for providing operation and maintenance (O&M) consultancy/advisory services for 800 MW Kudu combined cycle power station. It has submitted a bid to the Nigerian government for providing consultancy services to Niger Delta Power Holding Company for implementation of 7 mega power stations in Nigeria. NTPC has also filed bid with Electricite Du Liban, Lebanon for providing O&M services for a period of 5 years for Dier Amar and Zahrani gas based power stations each of 435 MW. The company has also participated in the tender floated by Eskom, south Africa for engineering and other services for 660 MW Matimba B project. The company as of December 2005 has received order for imparting training to power plant technicians of Oman Oil Refinery company at Muscat, Oman. A dedicated international cell has been created in NTPC for tapping emerging opportunities in the global market. Currently the cell is focusing in the middle east Asia-Pacific and African regions. The company, with operating capacity of 23,749 MW in India, has experience of working with equipment sourced from USA, UK, France, Germany, Japan, Italy and Russia. NTPC’s technology collaborators for various projects include ABB, Germany (Anta 413 MW), ABB, Germany (Jhanor-Gandhar 648 MW), GE, USA (GEC-Alsthom, France (Kawas 645 MW), Siemens, Germany (Dadri 817 MW).

Power sector registers 16 pc growth in April-Dec

January 4, 2006. Indian power industry has registered 15.5 per cent growth during April-December 2005. This was declared by Indian Electrical and Electronics Manufacturers’ Association (IEEMA). The industry experienced growth in areas such as transmission lines, switchgears and capacitors. Transmission lines showed a growth rate of 44 per cent and for switchgears it was 20.72 per cent. At the same time the industry has seen a shift in its domestic and exports sales ratio with the domestic sales accounting for almost 75 per cent of the total sales. The decisions taken by the ministry of power in the last 5 years are facilitating the growth of the industry. The growth for transformer sector was 10.5 per cent in the first quarter but the average growth for the three quarters was 6.93 per cent.

KSEB plans to invest $169 mn in FY06-07

January 3, 2006. The Kerala State Electricity Board (KSEB) is planning capital investments to the tune of Rs 760 crore ($169 mn) in 2006-07. The board will spend Rs 250 crore ($55.63 mn) on generation, Rs 218.50 crore ($48.62 mn) on transmission, Rs 290 crore ($64.53 mn) on distribution and Rs 1.50 crore ($0.34 mn) on other works during the year. As per the estimates of aggregate revenue requirement submitted to the State Electricity Regulatory Commission, the board proposes to start work on 16 new hydel projects in 2006-07 with a total installed capacity of 423 MW. The aggregate capital outlay for the projects is Rs 82 crore ($18.25 mn). These apart, three ongoing projects of a total installed capacity of 128.75 MW, are scheduled to be completed during the year.

The board will also invest Rs 40 crore ($8.9 mn) on the ongoing renovation and modernisation of Sabarigiri and Neriamangalam hydel projects in 2006-07. In the transmission sector, it plans to invest Rs 71.65 crore ($15.94 mn) on four 220 KV substations and transmission lines; Rs 52.73 crore ($11.73 mn) on ten 110 KV lines and Rs 18.86 crore ($4.2 mn) on three 66 KV lines. On the distribution front, the board is targeting 500,000 new connections. Besides, the programme for the year includes construction of 6,000 kilometres of 11 KV lines; 17,000 km of low-tension lines; installation of 8,500 distribution transformers and replacement of 400,000 faulty meters. The board has also made a provision of Rs 175 crore ($38.94 mn) under the Accelerated Power Development and Reforms Programme for the year.




PetroChina oil output on tech boost

January 10, 2006. PetroChina, Asia's largest oil producer, pumped 1.2 per cent more crude oil last year because of better technology. PetroChina produced 1.29 mn more tonnes of oil to 105.75 mn tonnes, the highest level since the unit was listed in 2000.  China's government is encouraging domestic companies to secure oil and natural gas supplies in domestic and overseas markets to ensure security of supply. PetroChina's Changqing oilfield in northwestern Shaanxi province contributed the bulk of the output growth, offsetting a decline in older fields. It pumped 9.42 mn tonnes of crude last year from that field, up 16.2 per cent, or 1.31 mn tonnes, from 2004.

Crude output at Tarim oilfield in remote western Xinjiang region rose 620,000 tonnes from the previous year, it said without giving a total for the year. Tarim produced 5.38 million tonnes of oil in 2004, company figures show. The company has been introducing advanced technology to slow output declines at its mature eastern oilfields. But the amount of crude pumped from its flagship Daqing oilfield in northeastern Heilongjiang province fell about 3percent to 44.95 million tonnes. Output at its second-largest oilfield, Liaohe, was kept at a "reasonable level."

Bolivia invites China to develop gas reserves

January 10, 2006. Bolivia has invited energy-hungry China to help develop his country's vast gas reserves after his government carries out plans to nationalize them. Bolivia wants private companies to remain as partners to develop them and will renegotiate existing contracts following Morales' inauguration on Jan. 22. Morales want to develop industries to turn Bolivia's gas into more profitable products such as cleaner-burning diesel instead of exporting it as a low-priced raw material. The left-leaning Morales, a former Indian activist, said he hoped to build ties between Bolivia's socialist movement and China's ruling Communist Party. China has signed deals to develop Venezuelan oil fields, and its investments in the region include a Brazilian steel mill and copper mines in Chile and Peru. For their part, Brazil, Argentina and other nations look to China as a source of investment and markets for their own exports.

CNOOC to buy $2.3 bn Nigeria oilfield stake

January 9, 2006. China's top offshore oil producer CNOOC Ltd. is to pay $2.3 bn for a stake in Nigerian oil and gas field, its largest-ever overseas acquisition. CNOOC will pay cash to buy the 45 per cent interest in Nigerian Oil Mining Licence 130, which includes the giant Akpo field discovered by global energy giant Total, from little-known Nigerian-based South Atlantic Petroleum Ltd. Akpo would start producing oil in the second half of 2008, and will contribute daily production of about 78,000 barrels to CNOOC, which pumped an estimated 410,000 bpd in 2005. CNOOC is paying $4.60 per barrel of oil equivalent (boe) for its Nigeria acquisition, compared with $7.30 per barrel paid by rival China National Petroleum Corp. for PetroKazakhstan.

Pak OGDC discovers gas and oil

January 7, 2006. The Oil and Gas Development Company Limited (OGDCL) has discovered gas and oil in commercial quantities at its Kunar Deep Well No 1 and Lashari Centre No 5 located in Hyderabad district, which will save $72 million per annum. These discoveries by OGDCL have opened new horizons for oil and gas exploration in the area. Initial testing has indicated presence of gas and oil with production rate of 41.4 mmcfd of gas and 330 barrels of condensate per day from the two zones in Lower Goru Formation. In Lashari Centre No 5, initial testing has indicated presence of oil with capacity of producing 1,065 barrels per day.

The Kunar well was drilled down to its target depth of 3,345 metres. Based on logs, geological and drilling date the production testing started on December 9, 2005 and initial short duration test produced 330 barrels of condensate per day with 41.4 mmcfd of gas at wellhead following pressure of 3,000 psi from the two zones. The preliminary estimate of total gas in place is about 680 bscf with 474 bscf of recoverable gas reserves. The recoverable condensate reserves are to the tune of 4.74 million barrels and this estimate will be updated after further appraisal of the discovery.

BP starts production offshore Azerbaijan

January 6, 2006. BP started production in another section of one of Azerbaijan's largest offshore oil fields, Azeri-Chirag-Gunashli (ACG) field in the Caspian. Oil from one of three wells at the West Azeri platform reached the Sangachal oil terminal, about 40 km south of the Azeri capital, Baku, on January 4. The terminal is the starting point for a 1,760 km US-backed pipeline that runs through Georgia to the Turkish Mediterranean port of Ceyhan and will bring Caspian Sea oil to Western markets. The West Azeri field, located about 100 km east of Baku. Total output from West Azeri is estimated to be around 70,000 b/d day in 2006.

West and East Azeri comprise phase II of the ACG project. This phase will represent more than 420,000 b/d when East Azeri comes on stream next year. Early oil production from Chirag began in late 1997. Central Azeri, which is phase I of the ACG project, came on stream in February 2005, and produced around 93,000 b/d in 2005. An average output of 230,000 b/d is expected in 2006.

The third phase covers the deepwater Gunashli field, which is due to begin production during 2008. This will bring the total ACG development to seven platforms. Total output from ACG will be more than 1 MMbbl/d by 2009. It is estimated that 5.4 Bbbl of oil and 100 bcm of natural gas will be recovered within the duration of the production sharing agreement. The entire Caspian Sea is believed to contain the world's third largest reserves of oil and gas. Other companies in the consortium include ExxonMobil Corp., Unocal, Norway's Statoil ASA (STO) and Azerbaijan's state oil company Socar.

Oil discovery by Total in Yemen

January 6. 2006. Total SA has discovered oil and successful production test of the Jathma-1 well in the East Shabwa Development Area (ESDA) on Block 10 in Yemen. Jathma-1 is the first of a three-well exploration program targeting a new area in the northern part of Block 10. The well reached TD of 3,175 m and tested 1,900 b/d of 35º gravity oil. Total holds 28.57 per cent interest in EDSA in partnership with Occidental Yemen Ltd., Comeco Petroleum Inc., and Kuwait Foreign Petroleum Exploration Co.

Japan to jointly explore disputed gas field

January 5, 2006. Japan has agreed to China’s long-standing offer to jointly explore for resources in disputed areas of the East China Sea. The agreement came after three rounds of talks, but the two sides have not agreed on how much to invest, or how to split profits.. China has been developing gas fields near waters which Japan claims, and Tokyo fears it could tap into resources lying under those waters. China does not recognise the midway line that Japan says separates the two.

Oil discovery at Gulf of Mexico by Chevron

January 4, 2006. Chevron Corp had made a another new deepwater oil discovery, at the Big Foot prospect in Walker Ridge block 29, about 225 miles south of New Orleans. Anadarko holds a 15 per cent working interest in the block. Operated by Chevron, the Big Foot discovery well is in approximately 5,000 feet of water and was drilled to a total depth of 25,127 feet. The well encountered as much as 300 feet or more of net oil pay. A sidetrack well has begun drilling to delineate the discovery.

Total begins production at Forvie North Field

January 4, 2006. Total’s Forvie North gas and condensates field has started production, nine months after official approval of the development plans by the British Authorities. Total owns 100 per cent and operates the field which is located approximately 440 kilometers north-east of Aberdeen in a water depth of 120 metres. Forvie North has been developed using subsea technologies and is connected to the processing and transport installations of Alwyn North, 33 kilometers away. The expected production of Forvie North at plateau is around 20,000 barrels of oil equivalent per day.

Colombia discovered gas & oil in Tayrona

January 3, 2006. There are indications of oil as well as gas in the Tayrona block located off the country's northern Caribbean coast. The company cited studies it is conducting along with Brazilian firm Petrobras and ExxonMobil. Preliminary studies of the Tayrona area show indications of the existence of reservoirs of gas and liquid hydrocarbons, which go beyond earlier expectations that the area had only gas. At 4.46 million hectares, Tayrona is Colombia's biggest off-shore exploration area but so far there are no projections about the amount of reserves it could contain. Colombia is one of the largest South American suppliers of oil to the United States. But exploration is only now increasing after a long period of relative inactivity since the 1980s when the country's guerrilla war started keeping prospectors away.


Sinopec's $3.1 bn Tianjin refinery approved

January 4, 2006. China's top refiner Sinopec Corp. has won government approval to build a $3.1 billion refinery-petrochemical complex due for completion two years ahead of an earlier target. Sinopec will expand its refinery in Tianjin to 12.5 million tonnes per year (tpy), or 250,000 barrels per day (bpd), and build a new 1 million tpy ethylene plant by 2008. Tianjin now has a 100,000-bpd refinery. The Tianjin ethylene complex will be China's second world-class petrochemical project after domestic rival PetroChina's Dushanzi plant in the country's northwest.

Sinopec, which submitted the plan to Beijing for approval in early 2005, will erect a new 200,000-bpd crude unit and secondary facilities including a hydrocracker to process sour crude with an average 1.5 percent sulphur content. The unit will replace the mostly low-sulphur grades the plant is processing now, and an ageing 50,000-bpd crude unit, which refines sweet and more expensive West African crude oil, will be mothballed once the new CDU is built. Chinese oil firms are planning to build or upgrade more than a dozen refineries before the end of this decade, adding more than 2 million bpd to the crude distillation capacity of the world's second-biggest oil consumer.

Transportation / Distribution / Trade

CanArgo Energy signed Kazakh gas contract

January 9, 2006. CanArgo Energy Corporation, its Kazakh subsidiary, BN Munai LLP has executed a natural gas supply contract with Gaz Impex S.A. The gas supply contract, which has a term until June 2014, is based on a take-or-pay principle and covers all gas produced from the Kyzyloi Field Production Contract area. Gas will be supplied to Gaz Impex at a tie in point on the Bukhara-Urals gas trunkline some 52 kilometres (32.5 miles) east of the Kyzyloi Field. The price of gas to be supplied at the tie in point averages $32 per thousand cubic metres ($1.13 per thousand cubic feet) over the life of the contract, with Gaz Impex providing bank guarantees against payment. CanArgo believes that this is one of the first take-or-pay contracts signed in Kazakhstan for a dedicated dry gas development. Gaz Impex is one of the leading gas marketing companies in Kazakhstan and is currently involved with gas purchase and supply contracts both within Kazakhstan and in surrounding countries.

The Kyzyloi Field Contract covers a 287 square kilometre (70,918 acre) area in southern Kazakhstan some 65 kilometres (41 miles) to the north of the border with the Karalkalpak region of Uzbekistan and 55 kilometres (34 miles) to the north-west of the Aral Sea. The field contains sweet natural gas (97% methane) reservoired in shallow sandstones at a depth of approximately 500 metres (1,640 feet). BNM is involved in an extensive workover and testing program of wells on the field, with the most recent well, KYZ106 now having been fully tested achieving a stabilised flow rate of 241,000 cubic metres (8.5 million cubic feet) of dry gas per day on a 30 mm (75/64th inch) choke with a flowing tubing head pressure of 16 atmospheres (228 psig). One further well remains to be tested for the initial development. Six wells have been tested to date which have flowed at a cumulative rate of 687,000 cubic metres (24.3 million cubic feet) of gas per day. A 60 kilometre (37 mile) pipeline will be constructed to connect the Kyzyloi development to the Bukhara-Urals gas trunkline, with the initial planned production rate being 500,000 cubic metres (17.7 mcf) per day. However, the results of the testing on the field to date has lead BNM to believe that by utilising early compression this initial production rate can be increased significantly. If early compression is used it would be expected to commence gas production at these better rates this summer, following delivery of the compressors.

Exploration drilling to date is proving that there is significant additional potential both in the Kyzyloi Field and in its surrounding Akkulka exploration contract area. As such the pipeline and associated facilities are being designed for up to 2.2 million cubic metres (78 mcf) per day of gas production. The ongoing exploration program in this area has resulted in two new shallow gas discoveries having already been made at the AKK04 exploration well and at AKK05 (now named North-East Kyzyloi). Testing has now been completed at AKK05 where the main reservoir interval flowed gas at a rate of 223,000 cubic metres (7.9 mcf) of gas per day, with gas also being tested from a thinner upper sandstone interval. One other exploration well remains to be fully tested while the AKK02 well is currently drilling, which will be followed by AKK01 well.

Nigerian LNG to US

January 8, 2006. Nigeria's multi-billion-dollar liquified natural gas company Nigeria NLNG had shipped the first cargo of gas from its fourth production plant to the United States. The consignment from the plant which only began production in November last year was loaded at the Bonny terminal in southern Nigeria for delivery to the Lake Charles terminal in the United States. The production had also started at the firm's fifth plant, known as a train, which is the last leg of its 2.1 billion dollar (1.7 billion euro) expansion programme aimed at raising earnings from gas exports to four billion dollars per annum.

Output from the five trains would raise Nigeria's LNG output to 17 million metric tonnes per annum. The coming on stream in 2007 of a sixth plant, Nigeria would be able to export 14 million metric tonnes of LNG per annum to Europe and eight million metric tonnes to US markets. The massive NLNG taps Nigeria's massive gas reserves and aims to reduce gas-flaring associated with the country's major oil industry by 2008.

Great Britain to import half of its gas by ‘10

January 5, 2006. Britain, once an energy exporter, will import about half of its gas needs by 2010. By 2020, existing North Sea gas fields will be supplying only 10 per cent of the gas needed in Britain. The existing pipeline to Belgium, which has been used to export gas to continental Europe, is being upgraded to be able to deliver 15 percent of the UK's peak gas demand by the end of this year. A new interconnector to be built between Holland and Bacton will supply a further 10 per cent. The biggest pipeline of all is due to be completed later this year. The Langeled pipe will link Britain directly to a huge gas field off the coast of Norway, which will be capable of supplying 16 per cent of the UK's peak demand when it is fully operational.

A small amount of gas is also imported as liquefied natural gas (LNG) via a terminal on the Isle of Grain, in Medway, Kent, which was opened last year. At the same time, new import terminals for LNG are being built at Milford Haven in Wales. Those terminals are due to start receiving gas in late 2007. When they are fully operational, they will be capable of handling about 20 percent of Britain's gas. The LNG for Milford Haven will be supplied under long-term contract from the Gulf state of Qatar. And by the end of the decade, Britain will have a reasonably diverse range of suppliers, including the Middle East and Norway. At present, 40 per cent of Britain's electricity is generated from gas.

Russia boosts gas exports to EU

January 4, 2006. Russia's state gas company Gazprom boosted natural gas exports to Europe to redress sudden shortfalls after it cut supplies to Ukraine, and offered some form of compensation for disruptions. Although Ukraine continued to siphon off gas from the European exports. Germany, Austria, Hungary, Poland, Serbia-Montenegro, Romania, Italy and France all decreases of up to 30 per cent in the amount of Russian gas received since Jan. 1. Russia would add 3.96 million cubic meters an hour of gas shipments to Europe to compensate for the shortages. Gazprom will also increase supplies to Europe through the Yamal-Europe pipeline that crosses Belarus and through the Blue Stream pipeline to Turkey.

Policy / Performance

Saudi Aramco keen on local tech alliances

January 10, 2006. Saudi Aramco, the largest oil producer in the world, is keen to have technical tie up with Indian hydrocarbon companies, including the Oil and Natural Gas Corporation (ONGC). Aramco is not interested in joint bidding for oil blocks in India. Because Aramco’s hand is full and have so many opportunities in Saudi Arabia and not have any plan to go outside. They need technical tie up as there is a shortage of manpower in Aramco. Aramco handles oil reserves of 265 billion barrels. Aramco had technical tie-ups in many countries including one in China. 

Russia, Ukraine gas prices agreed for 6 months

January 9, 2006. Gas prices in last week's deal to resolve a dispute between Russia and Ukraine have only been agreed for the next six months. A short-term agreement on gas prices raises the possibility of more rows and supply cuts to Europe this year. The pact between the ex-Soviet neighbours aimed to avert a repeat of a New Year supply halt that shook Europe. Under the deal, the price Russia pays for transporting gas across Ukraine, the route for 80 per cent of its exports to Europe, has been fixed for five years until 2011. Ukraine agreed to pay $95 per 1,000 cubic metres for Russian and Central Asian gas this price has only been set for the first six months of 2006.

BPC to float ‘petroleum bonds’ to raise money

January 9, 2006. The B’desh Energy Ministry has decided to float ‘petroleum bonds’ on the market to pay back bank loans to the tune of Tk 7,729.55 crore and collect money (1 billion US dollars) for import of oil in the current fiscal year. The Energy Ministry has requested Bangladesh Bank to make arrangements for floating ‘petroleum bonds’ on the market by February. The ministry will collect money from banks against these bonds."

The government would not arrange $ 2 billion to import oil from the foreign countries in the current fiscal year.  The BPC will collect about $ 1 billion from Janata Bank, Agrani Bank and Islamic Development Bank (IDB). In case the ministry fails to collect money, BPC will not be able to import oil with the country thrust into a fuel crisis. Of the four banks BPC owes Sonali Bank Tk 4909.41 crore, Janata Bank Tk 2206.66 crore, Agrani Bank Tk 410.72 crore and Rupali Bank Tk 202.76 crore. It has to pay Tk 150 crore in interest against the bank loans per year. Bangladesh needs 37 lakh tons of refined oil per year and BPC meets the demand by importing the product from Kuwait, Saudi Arabia and Dubai (UAE).

Pakistan granted exploration licenses

January 9, 2006. The Pak government granted exploration licenses to Petroleum Exploration (Pvt.) Ltd. on Blocks No. 2468-6 (Badin-IV North) and No. 2468 (Badin-IV South). The blocks cover 1,246.03 and 1,265.33 sq km, respectively. Badin-IV North is in Badin, Thatta, and Hyderabad districts of Sindh province, and Badin IV South is in Badin and Thatta.

PEL is to invest $11.15 million on geological and geophysical studies, acquisition, processing, and interpretation of 2D seismic data. It will drill three exploratory wells in Badin-IV North block and four in Badin-IV South block during the three-year phase one.

Algeria sees no need for Opec to cut output

January 9, 2006. Algeria believed Opec would not cut output when it meets at the end of this month, because prices were stable and demand still strong. It is expected that oil prices to remain above US$50 ($73.63) a barrel during the first half of 2006 but to drop a little in the third quarter.  Geopolitical disruptions like (the) gas row between Russia and Ukraine and (the) situation in Iraq and Israel are behind current prices. But the main factor is the demand, which is strong and will remain strong due to strong global economic growth. So, prices will not fall below US$50 a barrel in the next six months. They (prices) could decline a bit in the third quarter because demand is expected to fall by 2 million barrels a day.

Algeria is exporting 62 bcm of gas and would reach its target to sell 85 bcm in 2010 and 100 bcm by 2015. The Opec member country has started finalising deals for its second undersea pipeline bringing gas to Europe. Construction of the Medgaz pipeline, which will bring 8 bcm a year to Spain, Portugal and France, is due to be completed by 2009. Algerian state gas and oil group Sonatrach is in talks for gas exploration contracts in Mali, Mauritania and Niger. It also eyes projects in Asia's big market.

Saudi Aramco keen on local tech alliances

January 10, 2006. Saudi Aramco, the largest oil producer in the world, is keen to have technical tie up with Indian hydrocarbon companies, including the Oil and Natural Gas Corporation (ONGC). Aramco is not interested in joint bidding for oil blocks in India. Because Aramco’s hand is full and have so many opportunities in Saudi Arabia and not have any plan to go outside. They need technical tie up as there is a shortage of manpower in Aramco. Aramco handles oil reserves of 265 billion barrels. Aramco had technical tie-ups in many countries including one in China. 

Algeria, Pakistan discuss for energy sector tie-up

January 8, 2006. The Algerian and Pakistani energy ministers discussed ways for their two countries to cooperate in the hydrocarbons energy sector, particularly with regard to natural gas. The several possible areas of cooperation in the hydrocarbons sector were identified, such as the export of LNG and other petrol products from Algeria to Pakistan and the development of common gas projects. The two ministers also talked of a possible Algerian participation in a proposed transcontinental natural gas pipeline project linking Iran with Pakistan and India.

Kuwait to reap windfall from oil prices this year

January 8, 2006. Kuwait, the world’s fourth-largest holder of oil reserves, may generate three times more income from oil sales this fiscal year than it forecast because of higher- than-expected oil prices. The emirate’s oil sales may total more than $43.1 billion in the year to April 1, compared with $13.4 billion it forecast at the start of the fiscal year. The price of Kuwaiti crude may average $49.60 a barrel, compared with $21 a barrel the government forecast for its budget. The windfall will give Kuwait, with a population of 2.3 million, more money to invest in foreign companies and projects. 

Japan eyes 30 per cent cut in energy use by ‘30

January 6, 2006. The government will try to cut the ratio of energy consumption to gross domestic product by 30 per cent by 2030 to ensure the nation will have a stable supply of energy amid intensifying competition for resources. The Ministry of Economy, Trade and Industry plans to release the outline of Japan's new energy strategy around March and will ask the Advisory Committee for Natural Resources and Energy to flesh out a long-term policy possibly by June.

Japan's ratio of primary energy consumption to GDP is already the smallest in the world because of conservation measures spurred by the oil crises of the 1970s. This has improved 30 per cent over the past 30 years, and Tokyo aims to further accelerate energy-saving efforts by boosting technological innovations and enhancing energy efficiency.

The new energy strategy, which will be used to revise the basic energy plan, will also involve lowering Japan's dependency on oil and using more nuclear power. In the transportation sector, which is almost entirely reliant on oil, the government will try to reduce the dependency ratio to about 80 per cent by trying such alternatives as fuel cells and plant-derived ethanol.

Bulgaria rejects Gazprom bid to hike gas prices

January 6, 2006. Bulgaria is rejecting a Russian attempt to raise the price it charges for its gas, after Russia and Ukraine ended a price dispute that temporarily disrupted gas supplies to Europe. Russian gas giant Gazprom now supplies former Soviet satellite Bulgaria with a large part of its gas at lower-than-market prices for acting as the main conduit to its neighbours Turkey, Greece and Macedonia. Gazprom is pushing the Balkan state to switch to a system under which it pays transit fees in cash and Sofia buys all of its gas at market prices. But Bulgarian has rejected the proposal, saying their contract with the Russian company is good until 2010.

France to cut oil use by 2020 with new reactor

January 5, 2006. France plans to cut oil consumption in France, including the launch of the latest nuclear reactor prototype so that French trains will not use a drop of oil in 20 years' time. France has become the world's second largest nuclear power producer after it decided after the 1970s oil shocks to reduce its oil dependence by building a fleet of 58 nuclear reactors. France had to develop solar energy, electronic and hybrid diesel cars, and increase production of biomass fuels five times over the next two years.

State-owned nuclear operator Electricite de France has already launched plans to start up a new 1,600 MW European pressurised water reactor (EPR) in 2012, the so-called third generation reactor. But no new large power plants have been built since 1993 and France still needs to build more new power stations to meet growing demand and to compensate for ageing units.

The more sophisticated and supposedly safer fourth generation reactors, that have a pebble-bed reactor, where graphite pebbles are filled with particles of uranium dioxide fuel, are still being developed. Italy's biggest utility Enel has plans to take a stake in the third generation EPR project, but a deal has been delayed as it has yet to iron out the details of the framework agreement with EDF.

China resumes gasoline, naphtha export tax rebates

January 4, 2006. China has ended a slew of measures that were brought in last summer to fight domestic fuel shortages, resuming naphtha and gasoline export tax rebates and restoring import tariffs for diesel. Although the moves should give refiners a bigger margin from international sales of naphtha and gasoline, Beijing has kept a quota system that helps guarantee domestic supplies by limiting how much fuel can be sold abroad. China had suspended tax rebates - 11 percentage points of the 17% value-added tax charged on gasoline exports - from Sept. 1 to Dec. 31 to make it less profitable to export certain oil products. The moves came after pumps ran dry across southeast China.

The resumption had not been announced because the suspension had lapsed automatically, and rebates would continue at the same rates as in 2005. The naphtha rebate was 13 percentage points of the 17 per cent value added tax payable. Refiners had responded to the measures in the fourth quarter by cutting back sharply on gasoline exports, but they have resumed robust overseas sales in January as domestic stocks now appear plentiful. A 6 per cent tariff on imported diesel, waived in the last quarter of 2005 as harvest and heating needs stretched supplies, was also reinstated at the start of this year.

Mittal may cut gas use at Ukraine steel mill

January 4, 2006. Mittal Steel Co, the world’s largest steel maker it may cut gas use at its Kryvorizhstal mill in Ukraine after an accord by the country with OAO Gazprom means the cost for the fuel it gets from Russia will almost double. The company may use coke from its plants in Poland and the Czech Republic to fire its furnaces, reducing the amount of natural gas it uses in the Ukraine. Mittal may be able to reduce its natural gas consumption to 50 million cubic meters of gas a month, half of what it uses now. The rise in gas prices from Gazprom will have “minimal impact” on production costs. Mittal will not cut steel production at Kryvorizhstal, which is based in the southern part of the country. Ukraine will pay Russia $95 per 1,000 cubic meters for the fuel for six months, up from $50 under a previous arrangement.

Central Europe seeks less reliance on Russian gas

January 3, 2006. Five central European EU states agreed to act together on energy issues but stopped short of calls to diversify gas supplies away from dominant supplier Russia. Supplies of Russian gas flowing via Ukraine to the region fell sharply this week following Moscow's decision to halt deliveries to Ukraine due to a row over gas prices with Kiev. Central Europeans are concerned that Russia, which for decades dominated much of the region under communism, was using its near monopoly in energy supplies for its political goals, undermining the reliability of its deliveries.



France to launch fourth-generation N-reactor

January 5, 2006.  France, the world's second-largest nuclear power producer, is to launch a fourth-generation prototype nuclear reactor, which is scheduled to be operational by 2020 as well as symbolic targets for cutting France's reliance on oil in the coming decades. France will join forces with the industrial or international partners who wish to commit to the project, aimed at developing safer, cleaner and less costly reactors to meet future energy needs.

Underscoring the need to adapt to climate change, that oil would be gradually phased out in favour of alternative fuels on the country's public transport networks. National rail operator SNCF and the Paris metro company RATP should not consume a drop of oil in 20 years time. France is one of 10 countries in the Generation IV International Forum, which was launched four years ago following a US initiative and is conducting research into several new models of nuclear reactor.

Pak’s Punjab govt to set up two power stations

January 5, 2006. The Pakistan, Punjab government would build two hydraulic power stations at a cost of Rs 750 mn to ensure supply of cheaper energy to the industry. The first stage, the smaller power station would be set up on Upper Jehlum canal at a cost of Rs 250 mn and it would generate 3.2 MW electricity. The government was taking solid steps for the industrial development. The necessary infrastructure is being provided at the industrial estates.

Pak to buy nuke reactors from China

January 5, 2006.  Pakistan is negotiating to buy at least six nuclear power reactors from China during the next decade in its most ambitious nuclear facility expansion. Pakistan's nuclear shopping could cost as much as $10 billion. Islamabad’s talks with Beijing involve a minimum of six and a maximum of eight reactors.

China is considering Pakistan’s request to help it build eight more nuclear power plants at a cost of $8 billion aimed at generating 4,800 MW of electricity by 2015. The Pakistan Atomic Energy Commission (PAEC) had started planning to build Chashma-3 and Chashma-4, each with a capacity of 300 MW, following a broad understanding reached recently between the two countries. China believes Pakistan is adhering to the International Atomic Energy Agency (IAEA) standards and as such needs to be supported in its efforts to meet its electricity requirements of 8,800 MW by 2025.

China wanted to assist Pakistan in line with the “agreement in peaceful uses of nuclear energy” earlier reached between the two countries. China has assured Pakistan that it will transfer after some time ‘all possible’ nuclear technology to help build indigenous nuclear power plants.

US’s Lima Energy IGCC to upgrade power generation

January 3, 2006. Lima Energy Company, will upgrade of the Lima Energy IGCC (Integrated Gasification Combined Cycle) power generation facility to 600 MW from 540 MW. The increase in power output is a result of engineering optimization work and will enhance the project economic value. The project is currently in construction with concrete foundation work being carried out at this time.

The Lima Energy IGCC is the most advanced IGCC in the U.S.; leading a wave of expected IGCC development and construction activity accelerated by National Energy Policy and National Security interests. The synthetic gas is produced at less than half of today's market prices for gas, thus enabling the combined cycle power plant in the IGCC to produce low cost, clean and efficient electric power.

If the base- load coal fleet were converted to IGCC, the U.S. would benefit from up to 20 per cent more power and 10 times cleaner emissions from the same annual coal consumption.

Transmission / Distribution / Trade

Duke to sell power plants

January 10, 2006. Duke Energy Corp. will sell its Duke Energy North America power generation assets, excluding those in the Midwest, in a deal valued at $1.48 billion to $1.54 billion. At least four of the plants are in California, including two in the north part of the state.

Emerson wins $13 mn Korea's power plant contract

January 9, 2006. Emerson Process Management, has been awarded a $13 million contract to install its PlantWeb® digital plant architecture in Units 3 and 4 of the Yonghung Thermal Power Plant. PlantWeb architecture's Ovation expert control system will provide boiler control, automatic mill/burner control, furnace temperature monitoring, scrubber control and emissions monitoring.

The units also will use Emerson's advanced control software to optimize steam temperature, combustion and sootblowing. Emerson's Power & Water Solutions industry center will coordinate and supervise the project in partnership with Duon Systems, Ltd., of South Korea. Units 3 and 4 will each be capable of generating 870 MW of power and are slated to be operational by June 2008 and March 2009, respectively.

Policy / Performance

Russia seeks investors for $2.2 bn coal mine

January 9, 2006. Russia is seeking investors to develop a $2.2 billion coal mine in eastern Siberia, the nation’s largest deposit, as part of plans to increase domestic supplies of the fuel and boost exports to Asia. OAO Russian Railways, the country’s rail monopoly, plans to sell its 29.5 per cent stake in the Elginskoye site, which holds about 2 bcm of coal. The field is part of the Lensko-Tungussky coal region, the world’s largest by reserves. Japan and South Korea will be potential buyers of the coal. Russia plans to accelerate development of eastern Siberian oil, gas coal and gold fields, most of which are based in the Yakutia region. 40 per cent of Yakutia is within the Arctic Circle.

German energy summit to mull nuclear power

January 4, 2006. Germany will review plans to close nuclear power plants at a national summit after a dispute between Russia and Ukraine cut gas shipments to Europe. The German Chancellor had already planned meetings with energy industry chiefs and a summit on energy policy in February or March. Under pressure from the Social Democrats, Germany’s coalition in November said it won’t amend legislation that maps out a timetable for shutting all nuclear plants from about 2020. The Christian Democratic Union and its CSU sister party won a pledge from the SPD to review the law before 2009, the end of the legislative period.

German power prices to stay higher than EU50

January 3, 2006. German power prices will stay above 50 euros ($59) in the next four years as commodity prices remain high and the cost for power producers to emit carbon dioxide rises. German power for delivery in 2007 through 2009 will stay at a level of 50 euros a megawatt-hour or a bit higher. Stubbornly high fuel costs, combined with upwards pressure on carbon emission prices, look set to move up expectations of long-run power prices. Power prices in Europe’s largest economy surged last year, with the year-ahead contract rising more than 60 per cent to trade at a high of 53.85 euros a megawatt-hour on Dec. 29. Prices gained with the cost of fossil fuels, making it more expensive to produce fossil-based power.

Renewable Energy Trends


Ahmednagar NGO set to launch biodiesel project

January 9, 2006. Govind Gramin Prathisthan, an Ahmednagar-based NGO, is set to launch a pilot project to produce biodiesel from jatropha. The trial run is slated to begin in May. Till date a total area of 1,092 sq hectares of jatropha plantations has been raised. Some 20 lakh plants 2-5 ft tall are being grown in five villages of Ahmednagar since July 2002. Some of these plants have started yielding their first seeds this year.

In each of five villages, councils and groups were formed and the village needs evaluated. Based on this evaluation, planning for of the projects were done. Soil conservation formed 70 per cent of the project and water conservation 30 per cent. The NGO undertook the task of planting jatropha under the DPAP programme funded by the Government.

Carbon credit: $3.39 bn investments likely in India

January 9, 2006. The number of Indian projects, in the fields of biomass, cogeneration, hydropower and wind power, eligible for getting carbon credits, now stands at 225 with a potential of 225 million CERs (certified emission reductions. Each CER stands for one tonne of carbon dioxide reduction.). The Kyoto Protocol required the developed nations to reduce greenhouse-gas emissions of at least five per cent from 1990 levels during the commitment period of 2008-2012. It was estimated that the new opportunity could trigger flow of investments to the tune of Rs 15,000 crore ($3.39 bn). Projects approved by designated CDM (Clean Development Mechanism) in the developing countries could earn carbon credits and sell them to the countries that required reducing the greenhouse gas emissions under the international agreement. Any project that was set up after January 1, 2000, was eligible for CDM recognition. The Ministry had already started a project to sensitise and encourage States to take a lead in this regard. Initially five States — Andhra Pradesh, Rajasthan, Karnataka, Punjab and Maharashtra were given seed funding to set up their own CDM facilities and spread the word. Now it had been extended to 15 States.

450 MW wind power addition by Mar

January 7, 2006. The government said that around 450 MW of wind power capacity would be added by March-end, taking total capacity addition in the financial year to 1,200 MW. The country had added around 1,100 MW in the last financial year. The total wind power capacity is now about 4,200 MW. With the rapid growth in wind power, the country has attained fourth position in the world, surpassing Denmark this year. The government has decided to set up 500 district advisory committees across the country to attract investment from the private sector.

Kalam plans Asia’s big solar plant

January 6, 2006. A 5-MW solar plant will be set up in the Rashtrapati Bhavan will by the year-end, President A.P.J. Abdul Kalam said. It will be Asia's largest solar power plant. Emphasising the need to tap solar energy to bridge the demand-supply gap in the power sector, he said scientists would have to conduct research to increase the efficiency of solar cells from 15 to 45 per cent. At present, only kilowatt level solar plants were available in the country.


Colorado’s  BioEnergy to open biodiesel refinery

January 10, 2006. BioEnergy of Colorado, the state's largest biodiesel refinery, will open a new refinery, capable of producing 5 million gallons per year of biodiesel, will open next month near the National Western Stock Show stockyards. Biodiesel is a renewable fuel made from domestic agricultural crops, including soybeans, corn and canola. It can be used in diesel cars, trucks or buses. The company is investing $750,000 to bring the new plant online. BioEnergy's first plant produced and sold about 2.5 million gallons in the seven months it was operational in 2005.

US’s CPS Energy start wind power

January 10, 2006.  Texas based CPS Energy, is receiving 100 MW of electricity generated from its new Cottonwood Creek Wind Farm. This makes the local utility the largest publicly owned buyer of wind energy in Texas. This is enough energy to power 30,000 homes annually. CPS Energy signed a 20-year contract with renewable energy facility developer DKRW Energy LLC of Houston. It began construction of the wind farm last April at a site seven miles southwest of Sweetwater, Texas.

Shell and cos. to study German biofuel plant

January 8, 2006. Volkswagen, Royal Dutch Shell and Canadian biotech firm Iogen Corp. will jointly study whether to build a plant in Germany that can make cellulose ethanol, a biofuel that can cut cars' carbon dioxide emissions by 90 per cent. The partners signed a letter of intent at the North American International Auto Show to explore the project.

Privately held Iogen already makes cellulose ethanol from agricultural residue such as cereal straws and corn stover. Ethanol, an alcohol most often made from grains and sugar cane, is blended with gasoline to reduce tailpipe emissions in cars and trucks. Brazil is the world's leading producer and exporter of ethanol, derived from its huge sugarcane crop. It already blends its domestic gasoline with 25 percent ethanol and is looking to U.S., Japanese and Indian markets to boost exports. The International Energy Agency estimates that under the most optimistic scenario ethanol could make up 10 per cent of world gasoline by 2025.

Japan focus on oil with GTL and biofuel

January 7, 2006. Japan has set out an ambitious goal of replacing a fifth of its oil demand with biofuels or gas-to-liquid (GTL) fuels by 2030, but the plans will do little to ease its insecurity over imported energy supplies. Japan's energy agency has been working for more than two years to iron out long-term energy policy guidelines aimed at enhancing national security for the resource-poor country. So far the government has focused on limiting Japan's dependence on crude oil almost all of which is imported to 40 per cent of total energy needs from about 50 per cent currently. But a new draft due in February will be the first to specify a target for biofuel and GTL usage. It is expected to be formalised in June.

US’s Avista Corp plans to increase renewable power

January 4, 2006. Avista Corp is seeking more supplies of renewable energy to meet forecast demand for electricity in its Pacific Northwest service area. Avista plans to add about 35 MW of long-term renewable supplies beginning in the fourth quarter of 2007. Avista's utility unit has projected a shortage of energy supplies beginning in 2010 with power loads exceeding resources by 40 MW. The company, based in Spokane, Washington, currently supplies about 54 per cent of its electric needs through hydropower and it also uses wood waste and wind power to generate electricity.

Biomass-to-Fuel-Ethanol plant in Canada

January 4, 2006. MEMS USA, Inc., a California-based professional engineered systems, products and services company, plans to build a biomass-to-fuel-ethanol conversion facility targeting annual production of 227 million liters of fuel-grade ethanol in Ontario, Canada. At least 1.5 million long tons of biomass, approximately a three-year supply of raw materials, are now on HEO's Ontario site.

There is sufficient biomass in place within a 30-kilometer radius of the site to feed the plant at maximum operating capacity for at least 15 years. The site also offers superior rail access, immediate access to the Trans-Canadian Highway, proximity to a major natural gas pipeline, access to electric power and it is located within a large forest area.

The capital budget for the HEO project is US$150 million. MEMS recently entered into a MoU with a European funding group to provide the initial equity capital for the development of HEO and other Canadian biomass-to-fuel-ethanol conversion projects. MEMS has now located and is negotiating the acquisition of additional preferred sites for biomass-to-fuel-ethanol conversion projects in Eastern Canada.

Technip construct biodiesel unit in France

January 3, 2006. Technip has been awarded by Diester Industries a turnkey contract for a new biodiesel unit, based on the Axens process, to be built in Venette, near Compiègne, France. This project falls within the scope of the program set up by the French authorities for the development of biofuels, intended to reduce transportation-related pollution. This new unit, with a capacity of 100,000 t/y, will double the site's current production. The unit's start-up is scheduled for the third quarter of 2006.

This project marks a new step in the collaboration between Technip and Diester Industries, the pioneer and leader in France for the production of biodiesel, for which, in 1996, Technip built a unit in Rouen, France and is currently carrying out the construction of another unit in Sète, France.



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Publisher: Baljit Kapoor


Editorial team: Lydia Powell, Akhilesh Sati and Janardan Mistry.

[1] EPA Review on Biodiesel ( & Biofuels Report by Indian Planning Commission may be referred for details of testing & results on various other aspects and criteria of Biodiesel.

[2] Source: A Comprehensive Analysis of Biodiesel Impacts on Exhaust Emissions Analysis, EPA420-P-02-00/October 2002.

[3]Source: EPA Biodiesel valuation Report (

[4] Source: US-EPA, 2002.

[5]  Own compilation referring test results from various USA & India studies.

[6] Details of toxics emissions available at:

§ Can be contacted at [email protected].

[7] In recent years, there are number of studies pertaining to the dynamics of Asian energy security. While some of them have foresaw a competitive environment based on the energy security imperatives, that are portend to ignite conflict and rivalry, others have pointed towards the emergence of a pattern of interdependence based on sectoral complementarities that may enhance cooperation  in Asia. Some of the studies are Kent Caldor (1996), “Asia’s Deadly Triangle”, London: NB Publishing; Robert A. Manning (2000), “The Asian Energy Factor”, New York: Palgrave; and Daniel Yergin (1991), “The Prize”, New York: Simon & Schuster.

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