Oil Industry in Saudi Arabia: A Brief History Part - I

bd al Aziz ibn Abd ar Rahman Al Saud, the first king of Saudi Arabia, had not gained control of the western part of Saudi Arabia the country when he granted the first oil concession in 1923. A British investment group, the Eastern and General Syndicate, was the recipient. The syndicate gambled on the possibility that it could sell the concession, but British petroleum companies showed no interest. The concession lapsed and was declared void in 1928.

Discovery of oil in several places around the Persian Gulf suggested that the peninsula contained petroleum deposits. Several major oil companies, however, were blocked from obtaining concessions there by what was known as the Red Line Agreement, which prohibited companies with part ownership of a company operating in Iraq from acting independently in a proscribed area that covered much of the Middle East. Standard Oil Company of California (Socal), which was not affected by the Red Line Agreement, gained a concession and found oil in Bahrain in 1932. Socal then sought a concession in Saudi Arabia that became effective in July 1933. Socal assigned its concession to its wholly owned operating subsidiary, California Arabian Standard Oil Company (CASOC).

In 1936 Socal sold a part interest in CASOC to Texaco to gain marketing facilities for the crude discovered in its worldwide holdings. The name of the operating company in Saudi Arabia was changed to Arabian American Oil Company (Aramco) in January 1944. Two partners, Standard Oil Company of New Jersey (later renamed Exxon) and Socony-Vacuum (now Mobil Oil Company), were added in 1946 to gain investment capital and marketing outlets for the large reserves being discovered in Saudi Arabia. These four companies were the sole owners of Aramco until the early 1970s.

The original concession called for an annual rental fee of 5,000 British pounds (£) in gold or its equivalent until oil was discovered; a loan of £50,000 in gold to the Saudi government; a royalty payment of four shillings gold per net ton of crude production after the discovery of oil; and the free supply to the government of specific quantities of products from the refinery Aramco was to build after oil was discovered.

In 1933 the British pound was worth about US$4.87; there were twenty shillings to the British pound.) The company received exclusive rights to explore for, produce, and export oil, free of all Saudi taxes and duties, from most of the eastern part of Saudi Arabia for sixty years. The terms granted by the government were liberal, reflecting the king's need for funds, his low estimate of future oil production, and his weak bargaining position.

The original concession agreement was modified many times. The first modification was made in 1939 after the discovery of oil in 1938. This change added to Aramco's concession area and extended the period to 1999 in return for payments substantially higher than those specified in the first agreement and for larger quantities of free gasoline and kerosene to be supplied by Aramco to the Saudi government.

In 1950 a fifty-fifty profit-sharing agreement was signed, whereby a tax (called an income tax, but actually a tax on each barrel of oil produced) was levied by the government. This tax considerably increased government revenues. Further revisions increased the government's share--slowly until the 1970s and rapidly thereafter. At the beginning of 1982, Aramco's concession area amounted to about 220,000 square kilometers (189,000 onshore and 31,000 offshore), having relinquished more than 80 percent of the original area of almost 1.3 million square kilometers.

Once the existence of oil in quantity was ascertained, the advantages of a pipeline to the Mediterranean Sea seemed obvious, saving about 3,200 kilometers of sea travel and the transit fees of the Suez Canal. The Trans-Arabian Pipeline Company (Tapline), a wholly owned Aramco subsidiary, was formed in 1945, and the pipeline was completed in 1950. Many innovations were required to keep costs down and to make operations competitive with tankers. Tapline linked the Lebanese port of As Zahrani, close to Sidon to Al Qaysumah in Saudi Arabia (a distance of more than 1,200 kilometers), where it connected with a pipeline collecting oil from Aramco fields. Initial capacity was 320,000 bpd, but capacity was expanded, eventually handling 480,000 bpd in the mid-1970s.

Tax problems with Saudi authorities and transit fees due Jordan, Iraq, and Lebanon plagued Tapline for many years. The line was damaged and out of operation several times in the 1970s. And while operating costs of Tapline increased, supertankers were reducing seaborne expenses. By 1975 Tapline was no longer used to export Saudi crude via Sidon. In 1982 the line was again damaged. In late 1983, Tapline filed formal notice to cease operations in Syria and Lebanon, although small amounts of crude would reportedly continue, albeit temporarily, to supply a refinery in Jordan.

…to be continued

 

Does Iran need Nuclear Energy?

tatistics for the year 2002 issued by BP on November 2003 with the remaining oil reserves in Europe (mainly Britain and Norway) depleted between 5.4 years to 8.7 years, for UK and Norway respectively, and the US proven oil reserves at around 30.4 billion barrels (bb) with production rates of 7.6 million bpd, enough only for 10 years, the Middle East seems destined to become the main supplier of these markets in medium term while holding to their old markets for long time.

According to the most recent study conducted by the International Energy Agency, published in early November 2003, the world’s average rate of energy consumption is increasing by 1.7 per cent per annum. Persian Gulf’s five Giant oil producers, Saudi Arabia, Iraq, Kuwait, UAE and Iran are posed to supply a large portion of the oil market’s future needs-almost doubling their own products by the year 2030.

Middle East	Oil Reserves in Billion Barrels at the end 2004	Percentage of World’s total Reserves	Years Lasting (in context of production)
S.Arabia	262.7	22.1	67.8
Iran	132.5	11.1	88.7
Iraq	115.0	9.7	100+
Kuwait	99.0	8.3	100+
UAE	97.8	8.2	100+

Source: BP statistical review 2005.

An increased dependency of the US and Europe on the Middle East’s oil supply, should ostensibly, promote strategic importance of the region’s oil production capacity and with it, the overall importance of the role that the oil producing states would have to play in the world economy. But the significance of the Middle East’s oil could only be evaluated if the production capacity of the region would have proportionate bearing on state’s oil exporting potential. Or, the additional production capacity will then be nominated for home consumption only?

It is conceivable that an increased energy dependency of the industrialized sates on the oil exporting states of the Middle East would lead to closer economic cooperation and nevertheless, formation of closer bounding between the two sides. Such assessment would make sense if only the oil producers could manage to proportionately convert their increased production to an increased export capacity. In this kind equation, an increased domestic consumption by any oil producing states, whether it would be Iran or Russia, or else, would certainly have no positive effect on international oil market.

In the Persian Gulf, Saudi Arabia, Iraq, UAE, and Kuwait are all expected to do the job rather comfortably as their relatively small populations coupled with their modest domestic oil consumption, would help them to free additional capacities for export purposes. Where as, Iran is more likely to divert the extra production to the home market. Therefore Iran, unlike other four giants of the Persian Gulf, seems likely to lose the market challenges’, if she would fail to tasks:

·          Diversifying her domestic sources of supply

·          Securing sufficient capital investment for the oil industry in order to create additional production capacity (new investment in exploration and production plans as well as the existing 59 oil fields which require immediate attention to keep up the current rate of production)

·          Curbing the rate of oil consumption growth at home

·          Introducing new taxes on petrol, in favor of improving public transport and environmental issues

·          Gradually but steadily reducing petrol subsidies

·          Implementing a new energy efficiency program and promoting energy efficient industries

·          Turning to export oriented advanced technologies for the sake of increasing industrial out puts, rather than the policies designed to promote self-sufficiency. (For example, instead of cosmetic face lift from time to time, Iran’s inefficient and economically counterproductive car industry need to go though advanced structural changes matching the new age developments)

It is impossible of course to employ such measures without facing the hardships of all kinds, nor would it be possible to see the resulting changes appeared over night. As for Iran it takes 15 years before the energy sources of the domestic market would finely be diversified and rationally balanced. Cost wise, $40 billion investment over the next 15 years would be needed just to keep the current production capacity unchanged.

The world’s oil industry needs more than $3000 bn, investment until 2030, to meet the energy markets’ future demands. Interestingly, despite the control over 60 per cent of the global reserves, the investment allocation to the Middle East oil is about 20 per cent of the world’s total. Therefore, the region’s oil producers should work hard to stand a realistic chance of increasing their current production of 21 mb/d to the projected capacity of 51 mb/d by 2030. According to the IEA, by then, the Middle East would have market share increase of 15 per cent which equals two third of the world total increase.

… to be continued

Views are personal

Dr. Reza Taghizadeh, Consultant/Lecturer-Glasgow

 

Biodiesel as Diesel Substitute:

 

Assessing the Potential in Light of India’s Air Quality Goals & Energy Security Imperatives

Part- IV

Biodiesel Emissions Inventory Assessment

he observation in section 2.2 above is only an indicative appraisal for biodiesel and percentage reduction in g/km or g/kw-hr (exhaust emissions) may not necessarily translate into proportionately equal reductions or changes in air quality levels in ug/m³ as air quality is influenced by many sources and governed by a host of other factors. Another alternative may be assessing the changes in loading (thousand tons or tons or kgs, etc.) of pollutants under both cases of petrodiesel and biodiesel use in diesel vehicles. This approach also cannot directly account for changes in pollutant concentrations in ambient air but emission loads generated by various sources accumulate and get reflected as concentrations of pollutants in ambient air, i.e., air quality. This approach is therefore a reasonably better surrogate to air quality compared to tail-pipe emission measurements. Moreover, this is more practical as vehicle emission inventory in general has various important factors like vehicle population, usage, deterioration, fuel quality and technology effects, etc. already in-built and accounted for thereby reducing the uncertainties in our analysis. For this, we attempted to study the changes in vehicle emissions inventory with petrodiesel and B20 biodiesel. The vehicle emission inventories done by CPCB during 2001 for the cities of Mumbai, Chennai and Kolkata have been referred and the same reconstructed and estimated considering the relative effects of biodiesel on exhaust emissions of all conventional diesel vehicles as originally accounted for in the CPCB inventories. Table-4 below summarizes inventory results and percentage changes in emission loads with petrodiesel & biodiesel.

Column C of Table-4 shows the total emission loads from all vehicles whereas column D shows emission loads only from all diesel vehicles. The effects of biodiesel on vehicle tail pipe emissions as observed in Table-2 and the changes in pollutant load contribution as estimated in Table-4 are directionally consistent showing reduction in CO, HC, PM and increase in NO_X but, the effects are found to vary considerably in magnitudes or value terms (% change). For instance, biodiesel brings down exhaust CO emissions by as much as 38% (Table-2) whereas quantitatively, it may cut down vehicle CO load contribution maximum by 8% (Table-4, Kolkata). This signifies that substituting all diesel vehicles by biodiesel fuel may not necessarily effect or reduce the total loads in the emission inventory as severely or effectively as it reduces vehicle exhaust emissions. The vintage, total diesel vehicle population and existing air quality situation in a city appear to be the most important criteria for biodiesel fuel policy.

Under these conditions cities like Mumbai, Chennai, etc. having diesel vehicles mostly of mixed vintages and having greater allowance for NO_X air quality levels are better candidates for introduction of biodiesel. Cities like Kolkata having good number of diesel vehicles predominantly of older vintages and with existing higher NO_X levels exceeding the standard may appear unfit for the biodiesel option at the first instance. However, such cities need careful review considering the fact that predominantly older vehicles in turn may give substantially better benefits for CO, HC and PM with biodiesel ultimately offsetting the disadvantage of NO_X. Importantly, under all circumstances, B20 gives substantial advantage for PM and considering the issues of energy security and other benefits, biodiesel appears to be a good option for India.

4            Conclusions

Assessing the air quality scenario and potential impacts, we find biodiesel to be a reasonably suitable alternative for Indian cities. Along with major cities having high vehicle density, smaller cities also may easily adopt the biodiesel option as a proactive initiative. Undoubtedly, there is gain in CO, HC and PM but possibility of marginal increase in NO_X with biodiesel should not be a barrier to introduction of biodiesel in India as most of Indian cities fairly comply with the NO_X air quality standard. Even cities like Kolkata having higher NO_X levels may instead stand to gain substituting diesel vehicles with B20 as its in-use vehicle fleets being predominantly older in vintage & technology are expected to perform substantially better with biodiesel leading to excess reduction in CO, HC and PM along with drastic reduction in toxics emissions thereby offsetting the disadvantage of marginal NO_X increase.

Facts like energy security, prospects of domestic & village economy, reduction in oil imports bills, etc. make biodiesel a multifaceted utility fuel for India. Moreover, we should not forget the fact that biodiesel is probably the only alternative fuel which has been subjected to various successful field trials and feasibility studies in India and from regulatory and procedural point of view this automatically makes biodiesel ready for implementation in India at any point of time. Government may also opt for mandating a lower blend of biodiesel B5, i.e. 5% biodiesel compulsorily to be blended with conventional diesel as it has done for 5% ethanol in gasoline.

N.B. The views, opinions and statements made above are solely expressions of the author in his personal capacity and shall no way constitute to be part of any endorsements or opinions of the Organizations and Forums the author is attached to.

 

Concluded

Views are personal

Regional cooperation for Energy Security in Asia: Some Reflections

Part - IV

Dr. Samir Ranjan Pradhan

8. Market-Geopolitics Dilemma

he policy making for energy security in Asia is still at an evolving stage evincing dilemmas, contradictions and complexities. There is inherent dilemma with respect to reliance on market solutions or on enabling geopolitical configurations to address the energy security concerns. While on the one hand, the global energy sector, especially the world oil and gas sector, has transformed into a pattern of integrated and interdependent structure in the ambit of market liberalization and globalization; on the other hand, there are clear trends of energy politics in the regional context in Asia. With the transformation of world energy market shifting to Asia, that contains both major suppliers and consumers, the region itself is yet to cash on the changing geopolitics. The major consumers are yet to be integrated with the major suppliers and there is no sign of interdependence between consumers and producers within the region.

Asian oil and gas sector is under strict regulations and controls according to policies that put much weight on stable import sources and the supply structure is characterized by high dependence on the Gulf, basically exhibiting the features of a sellers’ market. There is also lack of regional marker crude which obstructs the development of integrated trade of flexible and fluid materials including crude oil and products and gas in the region. Major players in the regional oil and gas sector (the national companies as well as the respective governments) aim for stable supplies making the regional market less competitive in comparison to other regions of the world. The concerns of energy security particularly with respect to oil and natural gas has resulted in nationalistic oil security policies and zero-sum strategies, which may risk the disruptive impact on global oil market in the event of booming demand scenario in the near to the medium term scenario. Moreover, such competitive posturing has in fact inflated asset prices and E& P costs in areas which could have warranted lower prices in the true competitive market scenario[2].

Barriers of Energy Security in Asia

The above analysis of various contingent issues aptly implies certain barriers; those can be removed only through regional cooperation in order to ensure Asia’s energy security.

v  Traditional Energy Security strategy, Nationalistic policies, Regional competition for oil supplies, Mercantilist control of global equity supplies by national oil companies

v  No Asian giant oil companies to the stature of International Oil Companies (IOCs)

v  Insufficient Infrastructure: pipelines, Transportation Facilities, Distribution Systems, Buffer Stocking Arrangements, etc.

v  Lack of Financing mechanism for cross-border trade and investment

v  Lack of bargaining power as the major consuming and importing region, marginal role in global oil and gas scenario

v  Lack of group dialogue mechanism on urgent energy issues

v  Incongruent pricing policies and inadequate regulations

v  No integrated strategy between energy suppliers and consumers in Asia

v  Weak regional institutional and regulatory framework for regional planning, investment, financing, investment protection, contract enforcements and policy and commercial risk mitigation

v  Historical animosities, political and Security problems including territorial disputes, etc

v  Absence of suitable economic (political) organization in Asia-Institutional Deficit

v  Marginal influence in the political and economic stability of major producing regions such as Gulf

v  Vulnerable to intervention by superpowers

Rationale for regional Energy Cooperation

A comparison of the several national energy structures of surplus and deficiency in Asia suggests a significant asymmetry of substantial economic opportunities and liabilities. This makes the case for regional cooperation pervasive to take care of the energy security imperatives as well as augment regional economic integration in Asia. There is significant scope for advancing regional economic development by increasing energy access and supply and improving energy security, reliability and quality of life in the region. There are numerous potential spill-overs from more open regional energy trade, investment and infrastructure regimes that can augment economic integration in the region. This can act as a fundamental part of regional resource management and broader regional integration. This can supplement better accessibility to global investment and technology flows in the region. The major benefits of energy cooperation can be harnessed by exploiting complementarities and comparative advantages in regional energy endowments, experiences, technology developments, resource development costs and integration of complementary demand profiles. Regional integrated market offer enhanced opportunities from the economies of scale and comparative advantage in the global level. Cooperation also helps in accessing diverse import sources and faster outcomes for energy security. The bottom line of regional cooperation is to reduce costs of supply for all participants from the win-win opportunities. Energy cooperation in Asia will result in multidimensional (economic, security and geopolitical) benefits to the participants. The benefits of cooperation for energy security can be briefly pointed out as follows:

v  Diversifying regional oil import sources and lowering dependency on Middle East

v  Increasing negotiating power with respect to Gulf suppliers as a cohesive importing group and therefore more flexibility in contract with exporters

v  Diversification in fuel mix through increased import of natural gas

v  Concerted efforts to increase investment across the sectoral supply chain from prospecting to dispensing.

v  Technology and information dissemination to take care of the emergency preparedness in case of abrupt supply disruption

v  Involvement of government to remove obstacle to cross border trade and investment-lower investment risk and risk diversification among all stakeholders

v  Cooperative military security of the transportation channels will lower tension and substantially reduce animosity among countries in the region.

Areas of Cooperation

Some areas of outstanding opportunities for regional cooperation for energy security in Asia are as follows:

v  Regional cooperation for strategic petroleum reserve (SPR)

v  Cooperation for concrete policy and dialogue with OPEC

v  Collective dialogue with Gulf suppliers for the elimination of Asian oil premium

v  Cooperation for the establishment of Asian oil market and an independent regional marker

v  Cooperation for regional oil trading association comprising of national oil companies to participate in derivative trading for better risk management

v  Cooperation for trans-border LNG projects and gas pipelines

v  Cooperation for collective security of the oil and gas transportation channels, Strait of Malacca, Kara Isthmus, Indian Ocean, etc.

Views are personal

NEWS BRIEF

OIL & GAS

RIL to invest $1.13 bn in methane production

January 23, 2006. Reliance Industries Ltd will invest over Rs 5,000 crore ($1.13 bn) to start commercial gas production from coal bed methane (CBM) blocks by mid-2008. The company is planning to drill 1,000 CBM wells before 2009 and set up compressor terminals near the sedimentary basins to store and supply methane gas. CBM, an alternate source of clean and unconventional energy, is primarily methane gas in its natural state in coal or lignite bed seams. Terminals for CBM production include pumps, separators, compressor stations and pipelines. A single compressor station may process gas from 200 wells. The cost of one CBM terminal could be almost Rs 1,000 crore ($227 mn). Reliance has five CBM blocks covering an area of about 4,000 sq kms spanning Madhya Pradesh, Chattisgarh and Rajasthan. Oil majors such as Oil and Natural Gas Corporation, Gas Authority of India Ltd and Oil India Ltd are planning to begin CBM production by 2010. With coal reserves of 400 billion tonne in the country, the CBM resource potential is estimated to be to the tune of 35 to 40 tcf. 

RIL has also declared the quantum of investments in the Krishna Godavari basin fields where it struck gas. Reliance will need to invest $3 bn (Rs 15,000 crore) as capital expenditure for the development and gas production at the fields. The company has also deferred its deadline for commercial production of gas from the fields from March-April, 2006 to 2007-08. Subject to the RIL’s right to recover the capital expenditure from the sale proceeds of the natural gas produced from the field, the production of natural gas is to be shared with Government of India under terms of Production Sharing Contract.

OVL plans to spend about $1.52 bn in 2005-06

January 20, 2006. The Petroleum Ministry is examining ONGC Videsh Ltd's (OVL) demand for increasing its investment limit, which is currently set at $75 mn (or Rs 300 crore) whichever is less. OVL has approached the Ministry to consider empowering its board to take investment decisions and increasing the investment limit. Two options have been placed before the Ministry. The first option was to bring the investment limit in line with what is prescribed for the public sector enterprises, that is, an investment limit up to Rs 1,000 crore ($227 mn). The second option was the recommendation by the high-level Krishnamurthy Committee on Synergy in Energy of raising the limit to Rs 2,000 crore ($453 mn). Since investments beyond the permissible limit need to be approved by the Cabinet Committee on Economic Affairs, the company often lost emerging investment opportunities.

In 2005, the Government had increased the investment limit of OVL from $50 mn (or Rs 200 crore) to $75 mn (or Rs 300 crore). However, the company was of the view that such low investment limits had little relevance in the high-value oil and gas sector. The deal sizes, in which OVL would be interested, were in the range of $400-$800 mn (Rs 17.64 bn- Rs 35.29 bn). In 70 per cent of the deals, the buyers do not want to wait, and as a company into the business of acquiring equity in oil and natural gas assets overseas, OVL cannot afford to close such windows of opportunity. The company expects to spend close to Rs 6,700 crore ($1.52 bn) in 2005-06. ONGC, through OVL, has planned overseas oil and gas equity of 20 mt by 2010. ONGC has a transnational presence in 14 countries. So far it has acquired 23 projects in these countries. The projects are in Vietnam, Russia, Sudan, Iraq, Iran, Lybia, Syria, Myanmar, Australia, and the Ivory Coast. It is further pursuing oil and gas exploration blocks in Algeria, Australia, Indonesia, Nepal, Iran, Russia, the UAE and Venezuela.

GSPC bids for oil, gas blks in Muscot, Syria

January 18, 2006. Gujarat State Petroleum Corporation has submitted bid for the five oil and gas blocks of Muscat and Syria. GSPC has appointed PricewaterhouseCoopers (PwC) for preparing the business plan for forming overseas investment arm for block acquisition and hydrocarbon exploration. In Muscat, GSPC is bidding for three blocks, which are supposed to be rich gas resources. GSPC has submitted bid for two blocks in Damascus, Syria. The awarding of the blocks is expected in next four months. The company has bid for two oil and gas blocks in western Australia along with the same partners. This was the first venture of GSPC for exploration and production abroad. The result of the bid is expecting in March 2006. Both the blocks are located in gas and oil rich North West Shelf region of western Australia. GSPC has bid for blocks along with Oilex of Australia, Gail and Prize Petroleum-HPCL joint venture.

ONGC offers Aramco stake in Kakinada refinery

January 22, 2006. Oil and Natural Gas Corporation is planning to rope in Saudi Aramco as its equity partner for the 7.5-million tonne per annum (mtpa) Kakinada refinery project in Andhra Pradesh. Saudi Aramco is the world’s largest oil producer and India currently imports 24 mt of crude oil from Saudi Arabia. It also proposes a long-term crude supply agreement with Saudi Aramco for the refinery. ONGC has also offered marketing rights for retailing petroleum products in India to the extent of Saudi Aramco’s equity participation in the refinery project. With its rate of striking oil as high as 97 per cent for known fields and 90 per cent for unknown fields, a technical tie-up between Saudi Aramco and ONGC may also be on the cards. HPCL is also keen on roping in Saudi Aramco as its partner in the Vizag grassroot refinery project. The Kakinada refinery project is expected to cost Rs 5,500 crore ($1.3 bn). This refinery will produce oil that will comply with the latest emission norms and would be the first project in the world to have the capability to process bio fuels from the ground up.

IOC-GSPC shelves LNG terminal project in Gujarat

January 22, 2006. Indian Oil Corporation, along with Gujarat State Petroleum Corporation, has put on hold its plans to set up the third liquefied natural gas terminal at Pipavav or Mundra in the state of Gujarat. The decision to hold back the LNG terminal by IOC and GSPC comes at a time when the Shell’s LNG terminal at Hazira has been non-opeational for want of buyers of natural gas. Natural gas prices had seen a spurt in the spot market to around $7 per MMBTU. GSPC had already signed a MoU with IOC during Vibrant Gujarat Global Investment meet to explore opportunities for setting a third LNG terminal in Gujarat. The terminal had synergy with IOC’s plans to develop the Iran field where it plans to set up a 9 mtpa LNG liquefaction facility. Adani Group announcing plans to set up a toll-based third LNG terminal at Mundra has made IOC-GSPC’s LNG project viable. Moreover, IOC-GSPC can use Adani’s terminal for regassification purpose. GSPC also had discussion with the Qatar-based RasGas for the development of this project.

RIL plans 150 retail outlets

January 21, 2006. Reliance Industries plans to set up 150 retail outlets in the country, of which more than 20 would be in Gujarat. One of the two largest cities of the state — Ahmedabad and Surat — will have RIL’s first retail outlet in the form of a combination of a hyper market and a super market. For its retail outlets in Gujarat alone, in the first phase, the company plans to pump in Rs 3,000-5,000 crore ($680 mn). RIL is also looking for a third location on the Gandhinagar-Sarkhej highway. In the first phase, four cities — Jamnagar, Baroda, Rajkot, Bhavnagar and Surat — will have one RIL outlet each. Depending on the response, the company will increase the number of outlets or go in for hyper markets in addition to super markets.

HPCL buys Murban crude for March

January 23, 2006. Hindustan Petroleum Corp Ltd has bought 900,000 barrels of Murban crude for March loading in its monthly tender. HPCL bought the cargo of the Abu Dhabi sour crude from a European major. HPCL bought 1 mn barrels of sour Dubai crude for February loading in its previous tender. HPCL regularly buys 2 mn barrels of sweet crude on the spot market, either West African or Yemeni Masila grade, and Middle East crude through tenders, though less regularly.  But HPCL had not bought any West African grades this time. Unrest in Nigeria and surging oil prices may have prompted HPCL to prefer cheaper Middle East sour crude.

IOC's Paradip pipeline commissioning may be delayed

January 23, 2006. The commissioning of Indian Oil Corporation's Rs 1,178-crore ($267 mn) Paradip-Haldia crude pipeline inclusive of single buoy mooring and storage facility at Paradip may be delayed. The project was scheduled to be commissioned by March 2006. The 700-km pipeline will join Haldia-Barauni crude pipeline at Haldia, thereby replacing the existing system of supplying crude to Haldia and Barauni refineries of 6 mt each through Haldia port. Apart from ensuring assured supply of larger volume of crude, the project will reduce the crude transportation cost to both the refineries substantially. Haldia refinery will benefit the most from this and is expecting a net positive impact of $1 (Rs 44.13) per barrel in its gross refining margin. IOC has decided to expand the refinery capacity to 7.5 mt. A separate project has also been taken up to produce Euro-III grade fuel at Haldia refinery.

GSPCL to supply CNG to Vapi firms

January 20, 2006. Industrial units in Vapi are likely to get compressed natural gas supply from Gujarat State Petroleum Corporation for their captive power plants by this year end. GSPCL is planning to bring the gas from Surat to Vapi and companies including Reliance and Gail will distribute it in the local areas. Industrialists believe that this gas supply will help to bring down electricity costs and push up profit margins. GSPCL has plans to bring the gas from Surat to Vapi. The work will be completed by December 2006. Once the gas comes, companies like Reliance, Gas Authority of India Limited and Gujarat Gas Company will take up the task of internal distribution in the area. There are 1,200 units in Vapi industrial estate and 30 per cent of them are equipped with captive power plants. Industries in the area buy electricity at the rate of Rs 5.50 per unit from Gujarat electricity board. But captive plants that use diesel and furnace oil can generate power at Rs 2.50 to Rs 3.50 per unit. If CNG is made available, the cost of electricity generation will dip further.

Net oil import bill to go up 21 per cent

January 19, 2006.  The government has revised the net oil import bill for 2005-06 to $33.2 bn (Rs 1,48,269 crore), up 21 per cent against its original estimate of $27.4 bn (Rs 1,192,94 crore). This is almost 50 per cent higher than the actual net oil import bill of $22.9 bn (Rs 1,03,462 crore) last fiscal. The increase is primarily due to the high global crude oil prices coupled with lower domestic crude oil production, forcing the industry to go for additional imports of 2.61 mt of crude. This may see India’s current account deficit — already at a staggering $ 13 bn as on September 30, 2005 — shoot up further by the end of the fiscal. The current account deficit was only $6.2 bn for the first quarter. Increased crude oil imports during the year would mean an additional foreign exchange outgo of $12.38 bn. However, a net petroleum products export of 9.99 mt ($5.185 bn) in the current fiscal is expected to bring some relief to the exchequer. Domestic crude production for 2005-06 would be lower at 32.4 mt against the last year’s figure of 34.1 mt. Accordingly, higher crude oil imports have been planned for 2005-06 at 98.47 mt as against 95.86 mt in the previous year.

Shell, Total sign accord to sell LNG to GSPC

January 19, 2006. Royal Dutch Shell Plc, Europe’s second-biggest oil company, and Total SA signed an initial accord to sell as much as 2 mt a year of liquefied natural gas to Gujarat State Petroleum Corp. 500,000 tonne a year of the gas will be supplied from the Gorgon LNG venture in Western Australia and deliveries may start in 2010. Shell owns 25 per cent of the Chevron Corp-operated Gorgon venture, which so far has initial accords to sell LNG to customers in Japan and Mexico. The LNG will be shipped to the Hazira LNG receiving terminal, in Gujarat. Demand for gas in India, which started importing LNG in 2004, is increasing, driven by strong growth in the economy and demand for electricity, along with efforts to reduce pollution. Imports may reach 8.1 mt a year by 2010, from 2 mt in 2004. Shell, the world’s largest non-government-owned LNG producer, spent $667 million to build India’s second LNG terminal and a port at Hazira. The initial agreement was signed between Gujarat State Petroleum and Hazira LNG Pte, a unit owned 74 per cent by Shell and 26 per cent by France’s Total.

Myanmar gas sale to India with a rider

January 24, 2006. Myanmar is reconsidering sale of natural gas from A1- block to India, a step that would rekindle the prospects of a Myanmar-Bangladesh-India pipeline project. The rider is that New Delhi must provide a clear indication to Myanmar about its plan to evacuate this gas to India in a ‘‘time-bound manner’’. India has also been told that Myanmar is under ‘‘no contractual obligation to sell A-1 block gas to China’’ as the MoU with PetroChina did not mention any particular gas block. Myanmar had decided to sell A-1 gas to PetroChina with a view to monetising this gas at the earliest. The MoU was for sale of 6.5 trillion cubic feet of gas from its A-1 Block for 30 years. Myanmar said it signed the MoU with PetroChina because no progress had been achieved in the tripartite agreement between Myanmar, Bangladesh and India for the proposed pipeline project, whereas the Chinese had assured that they would lay their pipeline on time.

India can procure gas from Myanmar at $3.1-3.5 per million metric British thermal unit (mmbtu) at the well-head. India can propose a pricing formulation wherein the price of $3.3 per mmbtu at the ceiling at Brent price of $60 per barrel and the floor can be set at the Brent price of $20 per barrel (that comes to $2.05 per mmbtu). Based on this the gas delivered in the Indian market would be $5.1325 per mmbtu. According to the Centre’s approach paper for Myanmar Gas pricing, the proposed pricing profile is done in line with well head price profile for export to Thailand, however it is at a small discount.

India looks towards North Sea for oil

January 21, 2006. An Indian delegation comprising officials from the petroleum ministry, ONGC and OIL will be leaving for Aberdeen, the oil capital of Scotland shortly. The visit will enable Indian oil companies to explore possibilities of acquiring assets in the North Sea while increasing co-operation with Scottish companies in the hydrocarbons sector. One on one talks between oil companies on both sides would open up possibilities of co-operation. Scottish companies are open to offering stakes to Indian oil companies for acquiring assets in the North Sea. Scottish oil companies have expertise in drilling and down-hole technologies, subsea engineering and health, safety and environment. Apart from Cairn Energy, other smaller Scottish oil companies in talks with Indian players include Offshore Hydrocarbons Management (OHM) and Wood Group among others. OHM is in talks with ONGC and Reliance that are looking at gaining from the company’s unique technology that increases the success rate of finding oil through drilling. While ordinarily the success rate is 1:10, the superior technology by OHM increases it to about 1:4. With energy security on top of the agenda of the Indian government, the North Sea oil reserves should serve as an attractive area to tap. Remaining North Sea reserves are estimated to be around 2,000 mt and fields are expected to remain productive untill at least year 2020.

POWER

NHPC arm to take up 3 hydro projects in MP

January 24, 2006. The Narmada Hydroelectric Development Corporation Ltd has decided to execute and commission three hydel power projects in Madhya Pradesh. The NHDC is a subsidiary of the National Hydropower Development Corporation (NHPC) and the Madhya Pradesh government. The company, which has commissioned the 1,000 MW Indira Sagar power project, plans to construct the three projects of 60 MW each between Bargi (Jabalpur) and the Indira Sagar project. The Narmada Valley Development Authority has planned to invite private partnerships in these projects. Mandideep-based LNJ Bhilwara group HEG Ltd had shown interest. NHPC is aiming at starting construction on these projects by next year and completion by 2010. The three projects will cost the NHDC around Rs 550 crore ($124 mn) or more.

MAPS gets 30-yr fresh lease of life

January 24, 2006. Life extension works using indigenous technology have been completed successfully on Unit-1 of Madras Atomic Power Station (MAPS), thus giving the 22-year-old nuclear power plant a fresh lease of life for 30 years. The works have been completed in a record time of about 14 months. Around Rs 220 crore ($ 49.75 mn) was spent on upgrading Unit-1 of MAPS. Similar life extension works were undertaken and completed in 19 months on the Unit-II of MAPS, a constituent of the Nuclear Power Corporation of India Ltd (NPCIL), located at Kalpakkam. NPCIL is planning to invest about Rs 4,000 crore ($905 mn) in various projects during 2006-07 and was planning to borrow about Rs 2,000 crore ($452 mn) from the market. According to NPCIL, constructing a new nuclear power plant of 220 MW capacity would cost as much as Rs 1,100 crore ($249 mn).

NTPC to develop 2 ultra mega projects

January 24, 2006.  With the Centre envisaging power generation to the tune of 62,000 MW in the 11th Plan period, the state-run NTPC alone will be contributing over 20,000 MW to the proposed capacity addition. Of the 20,000 MW, NTPC would set up two pit-head coal-based ultra mega power projects with 4,000 MW capacity each at Lara in Chhatisgarh and Darlipali in Orissa. NTPC’s investment alone in the capacity addition would be close to Rs 80,000 crore ($18 bn). The first phase of capacity addition in Lara and Darlipali would be of 800 MW each and the total capacity to be added would be around 4,000 MW each.

Russia keen to supply nuclear plants to India

January 23, 2006. Russian companies are not only keen on supplying more nuclear power plants to India, but are also "confident" of being allowed to do so in course of time. Russia, being a part of the `nuclear suppliers' group,' is constrained by international agreements to supply equipment and fuel for nuclear power plants. (The two 1,000-MW power plants that are being put up at Kudankulam in Tamil Nadu with Russian technology are only a fulfillment of an agreement with India that predates Russia's international commitments). India's would put all the power plants built with foreign technology or fuels under international safeguards, but not those indigenously built and operated with domestic fuel. Putting indigenous plants under the safeguards would, in effect, mean following the provisions of the Nuclear Non-Proliferation Treaty (NPT), which India considers discriminatory and unjust. India has seven nuclear plants under construction now for 3,420-MW capacity, including the two at Kudankulam while 540-MW Tarapore-3 unit would be operational in a month.

Jindals to set up 1,000 MW unit

January 20, 2006. Jindal Photo Ltd (JPL), a flagship company of the B C Jindal group, has proposed to set up a 1,000 MW power plant in the Sidhi district of Madhya Pradesh. The company, which is primarily in the photo film business, has decided to diversify into power. The project is expected to complete by 2009. The company has sought government assistance on land acquisition. It will be a thermal power plant. The firm has asked the government for coal from NCL and water at 7,000 million cubic feet per hour. The project will come up in stages and the investment will be around Rs 6,000 crore ($1.36 bn).

 

M`shtra to buy 3000 MW from IPPs

January 20, 2006. The state is ready to buy 3,000 MW power from independent power producers in the state. In one year, the state government has signed MoUs for generation of 12,500 MW from independent power producers in the state. Most are in the 500 MW category and are coal-based plants. Of these, 6,000 MW is likely to start in six months. The state is ready to buy half the power generated by the independent producers. Almost all the applicants had submitted detailed project plans which were under consideration by the ministry. 

India clears loan for power plant in Sudan

January 24, 2006. India has cleared a loan of $392 mn in two lines of credit through export-import bank (Exim) for setting up a 500 MW power plant and a transmission line project in Sudan. The agreement was signed between Exim bank and Sudan’s ministry of finance. The project costs about $500 mn (Rs 22.11 bn) and is being shared by the two countries. Besides setting up a power plant for which a line of credit for $350 mn has been agreed upon, Exim bank also signed for another credit of $41.90 mn (Rs 1.85 bn) for setting up a transmission line and sub-station. The loan is for a period of nine years, plus a moratorium period of three years. The loan has been given at a fixed rate of interest of 4 per cent and the repayment would be made in cash. The government of Sudan has also given oil mortgage gurantee against the loan. This means, in case Sudan was unable to repay in terms of cash then it would be compensated through oil supply. Bhel will set up the project on turnkey basis with crude oil-fired boilers. The contracts for equipments would be placed within a month. The government of Sudan plans to expand the project to 3,000 MW to meet the country’s fast growing electricity needs.

India Inc charged up for power grids

January 23, 2006. Top companies, including Tata Power, Reliance Energy, Torrent and Essar Power, are planning to set up independent power transmission grids as the government is likely to open the sector for private participation. Several companies, including these four, have shown interest in setting up independent transmission grids. The government, however, was yet to finalise the guidelines for private investment in power transmission. The Centre has announced an ambitious plan to add around 100,000 MW of additional generation by 2012. In order to create additional grid capacity, it has planned to invest around Rs 71,000 crore ($16 bn). Of this, PowerGrid Corporation of India Ltd will invest about Rs 50,000 crore ($11.33 bn) and the remaining Rs 21,000 crore ($4.67 bn) will be brought in by private investors. The government will come out with revised guidelines on private investment in transmission soon. Under the guidelines that are being worked on, the government is considering both independent power transmission companies and joint ventures with state and central transmission utilities. In joint ventures, a private player will contribute 74 per cent of equity and state-owned utilities will hold 26 per cent. In an independent transmission company, private entities will own 100 per cent equity. Initially, the government plans to undertake pilot projects for both joint ventures and independent transmission. In the first joint venture pilot project, Tata Power is constructing a 400-KV transmission line from the Tala hydro electric project in Bhutan to Delhi. The project will be commissioned by July this year. For the independent transmission route, the government is planning to take up the 400 KV Bina-Nagda-Dehgam D line in the western region as the first pilot project.

Maharashtra to draw power from captive plants

January 22, 2006. The Maharashtra government, which is struggling to tide over the current power crisis, has indicated that it was prepared to draw maximum power from captive power plants provided by various industrial units, to run them at the full capacity. Maharashtra has a total captive power capacity of 1,500 MW. CPPs are keen that the government should compensate both variable and fixed charges. The per unit tariff from CPPs that run on high-speed diesel will be Rs 10 while it will range between Rs 5 and Rs 7 for those CPPs that operate on heavy oil, depending on base load or peaking load. The government expected that with sops at least 400-500 MW of capacity from CPPs could be connected to the grid. A high-level committee was examining the concessions to be given to CPPs. The government was considering exempting sales tax on diesel and naphtha for CPPs, which would help bring down tariff. CPPs are already exempted from payment of electricity duty. Some of the corporates having such CPP facility are Reliance Ind., which has captive capacity of around 400 MW, Indo Rama (60 MW), Jindals (50 MW), Standard Alkalis (30 MW), Tata Motors (25 MW), Mukand (20 MW), Reliance Infocom (14 MW), Century Enka (12 MW). There are large number of CPPs which have generation capacity ranging between 1 MW and 15 MW across the state.

Power Finance to fund 1,000 MW power in UP

January 21, 2006. The Power Finance Corporation of India has agreed to fund the expansion project of the Pariccha and Harduaganj thermal power stations located in Jhansi and Aligarh, thus adding a fresh capacity of 1,000 MW in power-starved UP. The PFC has communicated its consent to the UP Thermal Power Generation Corporation to fund the expansion project of Rs 2,660 crore ($603 mn). The remaining cost will be met from budgetary support by the UP government. The expansion plan includes 2x250 MW units at Pariccha and 2x250 MW units at Harduaganj. The expansion plan also includes setting up 3x110 gas-based thermal units at Panki in Kanpur, at the cost of Rs 1,000 crore ($ 227 mn), thus adding a total capacity of 1,330 MW.  

World Bank nod for $400 mn loan to PowerGrid

January 20, 2006. The World Bank today approved a $400-mn loan to Power Grid Corporation of India (PGCIL) to be used for the strengthening of power transmission system in the country. The loan extended by the International Bank for Reconstruction and Development (IBRD), the World Bank's lending arm, is a variable-spread loan with a maturity of 20 years, including a grace period of five years. The loan, backed by the Government's guarantee, has been earmarked for upgrading the power transmission system to increase reliable power exchange among various States and regions of the country. The Government's goal of universal access to electricity by 2012 would require "sizable additions" to generation, transmission and distribution capacities. The project seeks to improve service delivery of PGCIL by strengthening the transmission system in the power deficit regions and increasing inter-regional transmission capacity; and developing institutional capacity to facilitate the implementation of open access and inter-regional trading.

Nuclear solution to power crisis in Punjab

January 24, 2006. The proposal for setting up a 1,000 MW nuclear power plant in Punjab needs to be revived because it has no coal mines, and no access to the National Gas Grid. Demand for power is increasing at a rate of 500 MW every year. PSEB (Punjab State Electricity Board) said that the nuclear plant is the only immediate option before the state government to solve the power crises, an option which had earlier been ruled out because of security reasons. Moreover, the consumption of 84,000 tonnes of ash, which would have to be produced every day by the Ropar thermal plant, was seen as a great problem in the coming years. According to PSEB, in the ninth five year plan, therere was a proposal for 2505 MW of additional generating capacity from PSEB's own sources, but nothing has come up till date. In some countries like France, the share of nuclear power is more than 75 per cent. Here, the problem of ash disposal does not exist, and large areas for the ash dumps are not required. However, blowing ash has to be avoided, due to strong winds affecting agriculture and vegetation. Also, historical trends show huge risks in fuel prices in case of oil, and gas. Coal-based plants also release an almost equal amount of radiation, due to release of radon gas entrapped in coal.

India seeks Japanese funds in core sectors

January 24, 2006. India invited Japanese private investment in road and electricity sectors, extending bilateral cooperation where India is already the largest recipient of Official development Assistance (ODA) from Japan. Indian transmission sector was now fully open to FDI and power trading had been allowed to enable distribution companies to sell power to bulk customers. This was the ideal ground where private investors from Japan could look at extending their projects. India’s imports from Japan stood at $2.4 bn (Rs 106 bn) against its exports to Japan at $ 1.8 bn ($80 bn). Japan was the third biggest investor in India.

Power sector to get top priority: Manmohan

January 23, 2006. Prime Minister Manmohan Singh hinted that his government would give priority to power sector with efforts to find a solution to the problems faced by the sector. He would be giving attention to various aspects including ways to increase generation capacity to meet the growing demand for power. He said through the innovative scheme ’Rajiv Gandhi Grameen Vidyutikaran Yojana’ the government had committed to provide electricity to all the villages across the country by 2009. Dr Singh said under the Bharat Nirman scheme, the government would provide pucca roads, drinking water, electricity and telephone to each of the villages in the country by 2009.

Orissa for high rent from new power plants

January 22, 2006. Orissa, the pioneer in power sector reforms in the country, is now dictating terms on new power investments in the state. The state has kept as many as five power projects in waiting. The list includes Reliance Energy Ltd (REL), Neyvelli Lignite Corporation and Kolkata-based CESC. Since most of the projects are export-oriented, the state government is seeking free power from these projects, to the extent of 12 per cent. As an alternative, the state government is demanding Rs 5 crore ($1.13 mn) per annum on every 100 MW capacity. The state government has received proposals from five power companies to set up thermal power plants, aggregating a total capacity of 17,000 MW. The total investment in these projects would be to the tune of Rs 68,000 crore ($15 bn). While Reliance Energy has sent a draft MoU for setting up a 12,000 MW project at Hirma in Jharsuguda, public sector Neyvelli Lignite Corporation (NLC) has given a proposal to set up a 2,500 MW project in Angul district.

India needs solar energy, jatropha: President

January 21, 2006. India should increase the use of renewable energy to achieve energy independence and preserve and protect the environment, President APJ Abdul Kalam said. The main features of energy independence is to increase the use of renewable energy like solar energy on a large scale, establish large number of thorium-based nuclear power plants and go for massive plantation of jatropha which will lead to production of bio-fuel for the automobile sector. The President said the recent trends in the uncontrolled increase in the cost of fossil fuels have almost nullified economic advantage. He felt India and China, which would constitute half the world population by year 2020-30 and would need huge amounts of energy for their economic development, should shift their focus from fossil fuel to renewable energy sources as it was “the only way out for the two nations”.

Capacity addition in power depends on gas prices: Power Ministry

January 19, 2006. The planned capacity addition of power generation in the 11th five-year Plan could go up to 65,000 mega watts if gas prices stabilise in the next two years, said Power Ministry. Under the 11th five-year Plan, gas-based power projects have been kept to minimum, at 6,000 MW, given the uncertainty over the price and the availability of gas. However, if prices stabilise over the next year or two and gas availability is assured, the ministry will then consider adding a few more gas based plants and total capacity under the 11th plan may go up to 65000 MW. The Plan currently envisages adding 62,000 MW power to meet the projected requirement of 1,20,000 MW by 2012. Of this, 38,000 MW will be coal-based with 8,000 MW being generated from imported or blended coal and lignite. About 15,000 MW might be generated from hydel sources while 3,000 MW will be from nuclear power plants and 6,000 MW gas based plants. The Plan would also focus on ensuring continued coal supply to the power plants – by locating the plants in coastal regions and by building pit head plants.

National bio-diesel mission gets Plan panel approval

January 18, 2006. The Ministry of Rural Development has said the national mission on bio-diesel has got the in-principle nod of the Planning Commission. The Planning Commission had given nod to allocating Rs 50 crore ($ 11.3 mn) as part of the Rs 1,500-crore ($339 mn) National Bio Diesel Mission. The Rural Development Ministry will be the nodal ministry for implementing the programme, which is expected to start in 2006-07. The Internal Finance Committee is expected to meet on January 25 to discuss the project structure. The National Mission on Bio-diesel is proposed to be implemented in two phases. The first phase will involve a demonstration stage for plantation of jatropha on 400,000 hectares, and associated research activities for establishing the commercial viability of the fuel. Phase two will involve self-sustaining expansion of the bio-diesel programme. The overall objective of the national mission is to promote the creation of national infrastructure for production of bio-diesel through cultivation of jatropha plant and processing of its oil. The total involvement of Panchayati Raj institutions as the pivot of the programme needs to be recognised to ensure its success.

Uttaranchal to explore nuclear option

January 18, 2006. In its quest for becoming “energy state”, the Uttaranchal government is now exploring nuclear option. Besides making efforts to tap the potential of hydro and gas, the government has now established contact with Nuclear Power Corporation of India Limited (NPCIL), a public sector undertaking spearheading India’s nuclear power programme, to explore whether a nuclear power plant can be established in the state. The state has requested NPCIL to see whether a nuclear power plant like Narora and others can also be established in Uttaranchal. The government is presently keen to develop hydro power projects for which it has already identified 20000 MW of power potential in the state. The state government has adopted a target of achieving generating capacity of 500 MW every year and 3000 MW in five years. At present projects of 5307 MW capacity are under construction and projects of 6735 MW capacity have been allocated for implementations to big companies like NTPC, NHPC and THDC. In addition to hydro, the government has roped in the Gas Authority of India Limited (GAIL) to jointly examine various project opportunities for natural gas in the state and undertake extension of the National Gas Grid to Uttaranchal.

OIL & GAS

CNOOC in $3bn plan to increase production

January 24, 2006. CNOOC Ltd, China's largest offshore oil producer, is boosting capital spending by 35 per cent to US$3.06 billion (HK$23.87 billion) this year in an attempt to increase reserves and output after failing last year to meet production targets. The move comes as the mainland's three main oil companies, CNOOC and the far larger PetroChina and Sinopec, pull out all the stops to line up new sources of oil and natural gas to feed the country's growing need for energy. CNOOC will spend US$455 million on new exploration projects, a 72 per cent jump from last year. CNOOC aims to find sufficient new reserves to more than replace this year's targeted output of between 168 million and 170 million barrels of oil equivalent. Although reserve replacement is any oil company's bottom-line need, China's majors have far more ambitious goals - and needs - that are driving them to search far and wide for new reserves.

Russneft interested in TNK-BP's Udmurtneft

January 23, 2006. Fast-growing oil firm Russneft wants to buy TNK-BP's Udmurtneft production unit and other assets in Russia and abroad in a move to join the Russian major league. The privately owned, 280,000-barrel-per-day oil producer was created by company with the help of Swiss-based oil trader Glencore in 2003 and has been actively buying oil producing and refining assets since then. TNK-BP, Russia's second-largest oil firm plans to sell Udmurtneft, which has reserves of around 1 billion barrels of oil equivalent and produces around 120,000 bpd, or 6 million tons per year. Russneft is the most likely winner of the Udmurtneft auction, but would have to compete with China National Petroleum Corp. and India's Oil & Natural Gas Corp. Russneft's intention to buy a 49 percent stake in Slovak oil pipeline operator Transpetrol from stricken firm Yukos and the deal could total $100 million. Glencore, which has stakes in Russneft assets, had taken a share in three more. Russneft had reduced its share in Beliye Nochi, Gogoil and Kominedra to 51 percent in order to transfer the stakes to entities affiliated with Russneft, which would help it to consolidate its regional units.

Kerr-McGee to sell Gulf of Mexico stakes

January 23, 2006. Oil and gas company Kerr-McGee Corp. will sell its stakes in oil and natural gas properties in the Gulf of Mexico to W&T Offshore Inc. for $1.34 billion in cash. Kerr-McGee would see net after-tax cash proceeds of about $925 million from the deal, which would be effective from Oct. 1, 2005 and was expected to close in the first half of 2006.It estimated there were 363 billion cubic feet of natural gas equivalents of net proved reserves as of Oct. 1, 2005. Of that, 74 percent was natural gas.

Murphy gets Malaysia ultra-deepwater oil block

January 23, 2006. Malaysia's state oil firm, Petroliam Nasional Bhd had awarded an ultra-deepwater block in eastern Sabah to Murphy Oil Corp. and a Petronas subsidiary, Petronas Carigali. The block, Blok K, is a newly demarcated exploration area offshore the Malaysian state of Sabah on the island of Borneo. The block was part of the Block K acreage awarded to Murphy and Petronas Carigali in 1999, which had reached the end of its 7-year exploration period and had been partially relinquished to Petronas.

Cairn plans exploration in Bangladesh

January 22, 2006. British oil and gas firm Cairn Energy PLC plans for further exploration and development drilling in Bangladesh's offshore gas field. Cairn Energy is currently operating Bangladesh's only offshore gas field at Sangu in the Bay of Bengal, off Chittagong port. It has identified a new possible gas field at Char Jabbar under Noakhali district in block 10 with an indication of 2.8 trillion cubic feet (tcf) of gas reserves. Cairn also conducted seismic surveys at Meghnama and at Hatiya under the block 16. The possible gas reserve would be 3.5 tcf at Meghnama and 1.8 tcf at Hatiya. Cairn has been in Bangladesh for more than 10 years and, along with its joint venture partners, has invested $575 million. Cairn will invest another $50 million in 2006/07. Cairn holds a 90 percent interest in blocks 5 and 10, while the remaining 10 percent is with state-run Bangladesh Petroleum Exploration and Production Company Limited.

Statoil plans 30-40 exploration wells in 2006

January 20, 2006. Statoil ASA plans to drill 30-40 exploration wells in 2006, of which half will be on the Norwegian continental shelf (NCS) and the other half will be abroad. Long-term contracts for exploration rigs will allow increased drilling this year compared with last year. Statoil operates licenses in Algeria, Venezuela, and the Faroe Islands and plans to drill in these countries in 2006.

Uzbekneftegaz begins gas plant construction

January 20, 2006. State-owned Uzbekneftegaz has started construction of a $63.6 million LPG unit at its gas processing subsidiary Shurtanneftegaz in the Kashkadarya region of Uzbekistan. Shurtanneftegaz, one of three gas processing companies in Uzbekneftegaz, processes 11 billion cu m/year of gas. After three stages of construction, the plant will produce 175,000 tonnes/year of propane-butane mix by 2010. After the first stage of construction, to be completed by yearend, the unit will reach a capacity of 45,000 tonnes/year. Uzbekneftegaz plans to implement a number of projects to increase LPG production at the Mubarek gas processing plant and the Shurtan gas production complex.

ENSCO to build new ultra-deepwater semi

January 20, 2006. A wholly-owned subsidiary of ENSCO International Incorporated has entered into a drilling contract with two large independent oil companies to provide a new ultra-deepwater semisubmersible drilling rig, to be named ENSCO 8501. The drilling contract with Nexen Petroleum U.S.A. Inc., a subsidiary of Nexen Inc. is for a firm three and a half year primary term, with four one-year extension options at mutually agreed day rates. The term commitment is comprised of a two year obligation by Nexen and a one and a half year obligation by Noble Energy. The aggregate day rate revenue expected to be paid under the contract during the primary term is approximately $423 million. Under the terms of the agreement, ENSCO will also be reimbursed for mobilization and other start-up costs, and day rates will be adjusted for future variances in operating costs. Keppel FELS Limited in Singapore will construct ENSCO 8501 for ENSCO. The total construction cost is currently expected to be approximately $338 million, with mobilization to the GoM anticipated by the second quarter of 2009. ENSCO 8501 is the second semi rig in the 8500 Series, and ENSCO's third deepwater semi rig, joining ENSCO 7500, delivered in 2000, and ENSCO 8500, which is expected to be delivered in the second quarter of 2008.

ONGC, CNPC may bid for $3 bn BP oil venture 

January 19, 2006. China National Petroleum Corp and Oil & Natural Gas Corp (ONGC), the biggest oil companies in each nation, may be among bidders for a $3 billion venture in Russia operated by BP Plc. China Petrochemical Corp, Asia’s biggest refiner, is also considering a bid for the drilling venture. China may coordinate bidding by its state-run companies at a later stage. China and India, which consume 11 per cent of global oil production, need energy supplies to sustain the fastest growth among the world’s 20 biggest economies. Energy takeovers announced by the two countries more than doubled last year to $16.9 billion. The governments of China and India are more concerned about high oil demand in coming decades and that is going to drive a rise in energy deals, who helps manage $500 million of Asian stocks at IG Investment Ltd in Hong Kong. Both are also trying to cut reliance on areas under US influence, such as Saudi Arabia and Iraq. Malaysia’s state-owned Petroliam Nasional Bhd may also bid.

Indonesia seeking oil and gas investors

January 19, 2006. The Indonesian government plans to change clauses in oil and gas contracts to attract investors to difficult areas of the country, such as eastern Indonesia. The Implementing Body of Upstream Oil and Gas Activities, involve amendment granting greater shares of production to contractors. No oil and gas contractors would invest in eastern Indonesia if it received the same production shares as those offered in western Indonesia. The government would exempt oil and gas contractors wishing to invest in eastern Indonesia from drilling commitment fees and would reduce their exploration period from 6 months to 2-3 months.

Four gas fields start up in Dutch North Sea

January 19, 2006. Gaz de France, through its subsidiary GDF Production Nederland BV (ProNed) is bringing four natural gas fields on stream in the Dutch North Sea. The fields are north of Terschelling on Blocks G14, G16a, and G17a. ProNed, the production will be added to that of Block K2, northwest of Den Helder, which came on stream in December 2005. ProNed estimates total reserves of the five fields at 18 billion cu m of gas. ProNed's share amounts to 8 billion cu m. About 12.8 billion cu m has been purchased by Gaz de France. Maximum production capacity for the five fields is estimated at 7.2 million cu m/day, which includes 3.6 million cu m/day for ProNed.

UK’s Burren gets stake in blocks in Yemen, Oman

January 19, 2006. Burren Energy PLC, UK, is expanding its exploration operations into Yemen and Oman. By the end of February Burren expects to have parliamentary approval for a production-sharing agreement it signed with the Yemeni Ministry of Oil and Minerals for Block 6 in the prolific Shabwa basin. The 3,900 sq km block lies east of major oil and gas producing areas, previously operated by Hunt Oil Co., and west of Block S2, for which OMV AG recently received government approval to develop a 170 million bbl oil field in fractured basement reservoirs. Burren will focus on the basement potential on Block 6, which has not been explored by previous operators. It plans to acquire 3D seismic data over the most prospective area this year and target the basement structures for drilling in 2007. The 16,680 sq km block, operated by Oman Hunt, lies in up to 100 m of water in the Arabian Sea in the Masirah basin, which has similarities to the prolific oil and gas basins onshore Oman.

Shell group finds oil & gas in Malaysia

January 19, 2006. Shell Malaysia’s joint venture with Petronas and ConocoPhillips has made its fourth discovery with the Pisagan-1A exploration well on deepwater Block G off northwest Sabah, Malaysia. Shell said the Pisagan-1A exploration well, drilled to 1,465 m, encountered oil and gas.  Since 2003, the group has made three other oil and gas discoveries off Sabah: Ubah-2 in 2005, Malikai-1 in 2004, and Gumusut-1 in 2004. The partners in Block G are operator Shell Malaysia 35 per cent, ConocoPhillips (East Malaysia) 35 per cent, and Petronas 30 per cent.

Bangladesh expects 8 tcf of gas from new fields

January 18, 2006. Bangladesh will have an additional 8 trillion cubic feet (tcf) of natural gas from new discoveries in the next five years that will help ease its nagging shortfall of the fuel, international explorers have told the country. At present four international oil companies (IOCs) are engaged in the development and operation of 10 out of the country's 23 hydrocarbon blocks. State-owned Bangladesh Petroleum Exploration and Production Company (BAPEX) is working in some of the remaining blocks. The supply of gas would match its demand with total production reaching 1,650 million cubic feet per day (mmcfd) by June 2006. Bangladesh's total gas supply capacity is now 1,570 mcf per day, leaving a daily shortfall of 80 mcf. Bangladesh had worried over a sustainable long-term supply of gas. And the country would stop building new gas-fired power plants from 2012, while new ones will run on coal. Tata has offered to invest $2.5 billion in the fertiliser, power and steel sectors and have asked Bangladesh to ensure gas supply for 20 years, which Dhaka had agreed to guarantee. In the first phase, Tata would require 200 million cubic feet of gas per day. Bangladesh has 15.33 trillion cubic feet of proven and recoverable gas reserves, according to energy ministry estimates.

Gas discovery by Talisman Energy

January 18, 2006. Talisman Energy announced the discovery of several "high-deliverability" natural gas wells in the Canadian Foothills and the nearby Deep Basin, along with oil discoveries in Peru and the North Sea. Calgary-based Talisman made two gas discoveries in the Monkman area of northeastern British Columbia, one of Canada's most prolific new natural gas producing areas. One of the wells is expected to be producing gas by the fourth quarter of 2006, and the second well will be tied into Talisman-operated pipelines and processing infrastructure early this year. Talisman is drilling or evaluating five more wells in Monkman. In the Central Foothills of Alberta, Talisman tied in two wells at Cordel that are producing at 3.1 million and 3.5 million cubic feet of gas a day, respectively. A third well at Bighorn will be tied in during the first quarter. Talisman plans to drill 35 wells in the Alberta Foothills in 2006. Talisman also reported that one of its subsidiaries has participated in an oil discovery in Block 64 in the Maranon Basin in Peru. The partners involved are evaluating future plans for the new oil deposit. In the central British North Sea, a Talisman subsidiary has made an oil discovery next to the Balmoral and Beauly fields. The discovery was made in Block 16/22 and is operated by Talisman.

Total to apply for Canadian oil sands project soon

January 17, 2006. Total SA is filing its first application for a $9 billion Canadian oil sands project but may take another 18 months to decide where and when to build a major processing plant. Total, which paid C$1.6 billion ($1.4 billion) late last year to acquire control of the Joslyn development in Alberta, plans to apply to regulators for the first 100,000 barrel a day mining phase within weeks. The hard part is deciding where and when to build a plant to upgrade 200,000 barrels a day of tar-like bitumen from the oil sands into refinery-ready light synthetic crude, a facility that could cost $5 billion. Upgrading plans will be tied into refining opportunities. Total is not interested in just selling raw bitumen into the North American market, which prices the heavy crude at a deep discount. It is unlikely the upgrading plant would be in operation before 2013 or 2014. With overall output of 200,000 barrels a day from several phases as well as an upgrader, the project could cost about $9 billion. Total's plan for Canada is to produce 200,000 barrels of oil sands-derived crude by 2015, from Joslyn and Surmont.

NNPC, Oil Majors to float two refineries

January 19, 2006. The Nigerian National Petroleum Corporation (NNPC) and five of its joint venture partners have concluded arrangements to set up two new refineries in the country as part of efforts to expand domestic refining capacity and check capital flight occasioned by continued importation of petroleum products. Plans have also been concluded for the establishment of a Nigerian Content Support fund to provide working capital for Nigerian content activities and facilitate the achievement of government policy objectives in this direction. The Front End Engineering Design (FEED) contract for the construction of the refineries would be awarded next month by the corporation and its crude oil exploration and production partners including Shell, Mobil, Chevron, Total and Agip.

Sri Lanka’s decision on $795mn refinery soon

January 18, 2006. Sri Lanka is expected to decide on a new privately funded 100,000 barrel-per-day (bpd) refinery in weeks. A decision on the $795 million refinery, which will operate alongside an existing 50,000 bpd plant, had been expected soon after the November 17 presidential election but was delayed as officials consulted with unions. The facility will take between three and five years to build once the government gives the go-ahead. A lack of refining capacity means Sri Lanka, which produces no crude of its own, has to import some 40 per cent of its oil products, adding additional costs the island can ill afford after high global crude prices pushed inflation up last year. Sri Lanka imports 15 million barrels of oil products a year and spent nearly $1 billion on imports in the first eight months of 2005, up 34 per cent from a year earlier.

China Gas to double piped-gas projects

January 24, 2006. China Gas Holdings, a Hong Kong- listed piped-gas distributor in the mainland, plans to nearly double its city piped-gas projects to more than 80 over the next five years. The plan was unveiled after the company secured a 20 billion yuan (HK$19.24 billion) bank facility from China Development Bank. China's gas suppliers including SAR-listed Panva Gas Holdings and Xinao Gas Holdings are expanding their presence in the mainland as the government is encouraging the use of cleaner energy. China Gas, in which the mainland's top refiner Sinopec and India's GAIL own a stake, now has about 50 projects in China. The company is targeting new projects with average urban populations of more than one million, Liu said, adding that the company has more than 20 projects under negotiations. China Gas earlier planned to invest HK$5 billion to HK$6.7 billion per year in the year between 2006 and 2008 for piped-gas projects, with 30 percent from internal sources and 70 percent from debt financing.

Petronas to supply gas to Shikoku

January 23, 2006. Malaysia's national oil corporation Petronas that a gas subsidiary will supply liquefied natural gas to Japanese power company Shikoku Electric for 15 years from 2010. Malaysia LNG signed a confirmation of intent with Shikoku in a deal that will see it supply up to 420,000 metric tons annually of liquefied natural gas (LNG), with an option to extend for another five years after 2010. MLNG was selected as the only supplier of LNG for Shikoku Electric from a list of five other LNG companies. The gas will be supplied to Shikoku Electric from its LNG complex in Bintulu in Malaysia's eastern Sarawak state, and shipped in tankers owned by another of its subsidiaries, MISC.

NLNG ships first Train 4 cargo for Total

January 23, 2006. Total SA’s first cargo of LNG from Nigeria LNG Train 4 left Bonny Island Jan. 23 under a 1.15 million tonne/year agreement between Total Gas & Power Ltd. and NLNG for LNG from Trains 4, 5, and 6. NLNG's Train 4 started production in fourth-quarter 2005, and Train 5 is being prepared to start up next month. The two trains will increase NLNG's production capacity by 8 million tonnes/year to more than 17 million tonnes/year. Train 6, currently under construction, will increase the plant capacity by 4 million tonnes/year. Total holds a 15 per cent stake in NLNG, a Nigerian joint venture company. Other shareholders are Nigerian National Petroleum Corp. 49 per cent, Royal Dutch Shell PLC 25.6 per cent, and ENI SPA 10.4per cent.

Turkey imports oil mostly from Russia, Iran

January 22, 2006. Turkey's import of crude oil from Russia booms since the country meets almost all of its oil need from foreign countries. Oil import from Russia rose from 84,000 tons to 6.8 million tons in four years. Thus, Russia has become the most important crude supplier for Turkey as well as natural gas. Iran is the number one country Turkey imports crude oil from. More than half of the 23.5 million-ton crude oil import in 2005 was made from these two countries. Turkey paid $5.6 billion for the import of 22.2 million tons oil in 2004 and spent $8.6 billion last year. Its only oil refinery, TUPRAS, announced the figures of crude oil and oil products for 2005. Turkey imported 23.5 million tons of crude oil in 2005, 6.9 million tons from Iran, 6.8 million from Russia, 4.5 million from Libya and 938,000 from Iraq, 325 tons from Syria, and the remaining 395,000 tons were supplied by other oil producing countries.

Last year, TUPRAS did not import any oil from a former import country for Turkey, Algeria; and decreased the amount of oil purchased from Saudi Arabia. In the same term, TUPRAS realized a 23.8 million tons oil production of gas, diesel fuel, liquid petroleum gas (LPG) and gas oil, which corresponds to an increase of 1.1 million tons a year. The company's oil products import in 2005 of 959,000 ton remained the same as in 2004, and its export rose from 3.2 million tons to 4.3 million. Turkey meets its entire need of natural gas from foreign countries as well and has no possibility of storing gas. The same is almost applicable for crude oil. The oil stock is kept in BOTAS Petroleum Pipeline Corporation's pipelines and TUPRAS refineries.

Indonesia, Amerada sign gas supply deal

January 20, 2006. Indonesian state power company PT Perusahaan Listrik Negara (PLN) has signed a preliminary deal with Amerada Hess to supply gas to a power plant in Jambi in central Sumatra. PLN will use the gas from Amerada to supply a 180 MW power plant in Jambi. Amerada will supply 80 million cubic feet per day of gas from 2008 for 12 years. PLN will get gas from the Jambi-Merang block, in which state oil company Pertamina has a 50 per cent stake, Amerada 25 per cent and another local company Pacific Oil and Gas 25 per cent. PLN has said it will cut the use of oil products by around 18 per cent this year as it looks to counter soaring crude costs. Some 30 per cent of PLN's plants use oil products such as diesel and fuel oil.

Gazprom’s LNG cargoes to the US

January 20, 2006. Russian gas giant Gazprom plans to ship at least six cargoes of liquefied natural gas to the United States this year in a partnership with energy major Shell. LNG is gas which has been cooled into liquid form for easy transport by tanker. Gazprom entered the global LNG market last year when it sent two shipments to the United States. The company does not produce any LNG of its own and acquired those cargoes in swap deals in return for pipeline gas deliveries in Europe. These two cargoes were delivered to an import terminal at Cove Point in Maryland on the US east coast where Shell owns regasification capacity. Gazprom has multiple LNG projects, all of which are set to come on stream at the end of this decade. The company is keen to carry out swaps to learn more about the LNG business.

Chicago signs gas supply deal with BP

January 19, 2006. Owners of the Aux Sable natural gas liquids plant near Chicago had agreed to sell all the plant's output to BP Plc under a 20-year deal aimed at guaranteeing the facility's profitability. Aux Sable, owned by Enbridge Inc. Fort Chicago Energy Partners and Williams Cos. Inc., processes liquid hydrocarbons stripped from natural gas that flows on the Alliance pipeline from northern British Columbia. Under the deal, BP will pay Aux Sable a fixed annual fee and percentage share of any net margin above set levels. BP will also pay the owners for all operating, maintenance and capital costs associated with the Chicago plant. The agreement, expected to be finalized by March 31, will give BP the option to extend the contract by 10 years.

Woodside Pete seeks to ship LNG to California

January 18, 2006. Australia's Woodside Petroleum Ltd. plans to join the ranks of oil and gas companies vying to supply liquefied natural gas into the California energy market. It could supply about 10 per cent to 15 per cent of the state's supply of gas, which now comes mostly from Canada, the U.S. Southwest, and the Rocky Mountain area. The company plans to deliver the LNG via tankers to a site at least 15 miles off the Southern California coast, where it would be converted back to gas aboard the tankers and delivered to shore through a pipeline on the seabed. With tightening gas supplies in North America and rising prices, Woodside can tap reserves in Australia as a source of LNG for California. Woodside would join energy competitors from Australia, Japan and the U.S. targeting California's appetite for gas for its power plants and other uses. California consumes about 6.4 billion cubic feet a day of gas, with half of that used as fuel firing power plants, according to the state's Energy Commission. Gas demand in the state is projected to rise by 0.7 percent a year from 2006 through 2016, below the 1.6 percent annual growth seen for the U.S. Energy efficiency programs are cutting into the state's demand. The company would deliver 700 million cubic feet LNG a day to California and have capacity of 1.4 billion cubic feet a day if the project proceeds.

Exxon Mobil to exit Azerbaijan fields

January 24, 2006. Exxon Mobil Corp. will pay a $50 million claim after refusing to continue drilling at two offshore fields in the Azeri sector of the Caspian Sea. Exxon Mobil will pay $32 million to exit exploration of the Zafar-Mashal deposit and $18 million to stop work at the Nakhichevan deposit. Exxon was scheduled to drill second wells at both blocks after the first wells didn't discover commercially viable reserves. London-based BP, Europe's biggest oil company, leads a group that includes Exxon Mobil and is developing the Azeri-Chirag-Gunashli field, the biggest source of oil in Azerbaijan. International companies are exploring the Caspian Sea, which may have oil reserves second only to the Middle East, after oil prices doubled in the past five years.

Saudi, China sign energy deal 

January 24, 2006. China and Saudi Arabia signed several deals, including one on energy and possibly a refinery. Both sides sought to use their burgeoning oil business as a basis for broader economic and diplomatic cooperation. Saudi Arabia is already the largest supplier of oil imports to China, which has been scouring the globe for crude to feed its booming economy, tempting potential partners with the prospects of its huge market. China is one of the most important markets for Saudi oil and Saudi oil is one of the most important sources of energy for China. Saudi Arabia supplied nearly 440,000 barrels per day (bpd) of oil to China in the first 11 months of last year, 17 per cent of China’s imports. The energy deal set a ‘framework’ for investment, but actual investment would have to come from companies, adding Saudi and Chinese firms had extensive contacts. Details on the energy deal were not immediately available.

Gazprom signs deal for more Uzbek gas

January 23, 2006. Gazprom had signed a deal to buy more gas this year from Uzbekistan, helping to secure supplies for Ukraine under its controversial deal with trader Rosukrenergo. It would buy 9 bcm of Uzbek gas in 2006, up from 8 bcm in 2005 and 5 bcm in the previous years. Under Gazprom's Jan. 4 contract with Swiss-registered Rosukrenergo, the trader is to buy 41 bcm of gas from Turkmenistan, up to 7 bcm of Uzbek gas and up to 8 bcm of Kazakh gas for onward sale to Ukraine. Gazprom agreed to pay 25 per cent more for Uzbek gas, increasing the price to $60 per 1,000 cubic meters.

France calls for more EU energy investments 

January 22, 2006. France is calling for more investment in energy production and stockpiling of supplies as part of a common European Union energy policy. The range of measures, which France plans to present to a meeting of EU finance ministers next week, are the latest sign of growing momentum for a common EU policy after a pricing dispute between Russia and Ukraine, which disrupted gas supply to Europe, highlighted the EU's vulnerability as a major energy importer. France's proposals called for the EU to study a multi-annual investment programme in the production, transport and storage of energy supplies. They included opening an EU coordination centre to exchange information between the different transporters of electricity in the EU's 25 member states and "harmonising" the powers of national regulators of gas and electricity markets. The proposals also suggest creating a system of energy saving certificates that could be traded on a market in an effort to get households to reduce their energy usage.

The EU already has an emissions trading scheme, in which big polluters like power companies trade the rights to emit carbon dioxide (CO2), the main gas blamed for global warming. France called for the EU to study measures that would encourage replacing oil with substitutes, especially in the areas of heating and electricity production. It also called for a regular report on the state of European oil stocks. France's proposals also encourage EU member states to invest more in development of renewable energy sources. The EU's dependence on foreign energy sources is increasing as its own supplies run out. The European Commission forecasts import dependence could grow to 70 per cent of general energy consumption by 2030 and 90pc for certain fuels like oil.

UK's BG Group signs Nigeria production sharing

January 20, 2006. UK oil and gas producer BG Group Plc had bought a 45 per cent interest in Block 332 offshore Nigeria under an agreement with Sahara Energy Exploration & Production Ltd. The deal, which will see it become operator of the block, marked its entry into the Nigerian upstream sector and did not disclose financial terms of the agreement. The gas-focused firm was not deterred by militant attacks in the Nigerian Delta region which have disrupted production at facilities operated by Royal Dutch Shell Plc in the past week. BG previously agreed to buy Nigerian liquefied natural gas (LNG) to ship to U.S. and European markets.

Shell, ONGC sign cooperation agreement

January 20, 2006. Royal Dutch Shell PLC and Oil & Natural Gas Corp. of India have signed a MOU covering upstream and downstream projects, mostly in India. The agreement covers exploration and production of hydrocarbons and distribution of natural gas and oil products. It will also look into refining, petrochemicals, and coal gasification. While giving Shell greater access to Indian projects, the MOU will allow ONGC more opportunities outside the country. There will be a joint steering committee to manage cooperation and identify other investment opportunities. The steering committee will look at opportunities for raising production from existing fields and jointly bidding in future exploration rounds. Downstream, the committee could recommend a long-term oil products supply arrangement and joint operation of terminals and depots.

The sign is also including the Sakhalin-II fields in Russia. ONGC which has a 20 per cent stake in Sakhalin-I, was looking at the possibility of picking up a stake in Sakhalin-II and tying up gas from the two projects to make its shipment viable.

Inpex plans double oil, gas production

January 20, 2006. Japan's Inpex Holdings Inc. plans to more than double oil and gas output in 10 years to secure energy for a country that lacks its own reserves. The company, Japan's biggest oil explorer, aims to raise output to the equivalent of 1 million barrels of oil a day, which Inpex Corp. agreed to buy in November. Production of 1 million barrels a day is about a quarter of Japan's crude oil consumption. The combined company plans to raise production at an annual rate of 8.7 percent to 563,000 barrels a day by the year ending March 31, 2010. LNG prices including insurance and freight gained 34 percent to 40,678 yen a metric ton in November from a year ago after crude oil prices imported into Japan, used in determining LNG prices, rose 50 percent in a year. Teikoku Oil and Tokyo Gas Co. would study building a 100-kilometer (62-mile) gas pipeline costing about 30 billion yen to supply the Japanese prefecture of Gunma. The first 20 kilometer stretch will be built starting this year at a cost of about 6 billion yen.

Gazprom seeks direct German sales

January 20, 2006. Gazprom is looking to sell directly to German end-users of gas, as the gas monopoly plans to expand its market presence.  The company's first priority was to look for a German partner to form a 50-50 joint venture. Gazprom currently has Wingas, a joint venture with BASF's Wintershall to sell natural gas in Germany and Europe. Wingas has a 15 per cent share of Germany's wholesale gas market. Gazprom aimed to boost its share of Britain's wholesale gas market to a fifth within 10 years, and would consider acquisitions as big as Scottish Power.

China approves two PetroChina product lines

January 19, 2006. PetroChina has obtained approval from the Chinese government to lay two pipelines to carry oil products from the northeastern and northwestern areas of China to the country's central regions. PetroChina will invest about $1.5 billion to construct the two lines, which are expected to become operational as early as 2007. One pipeline will extend from Lanzhou, in northwest China's Gansu Province, and carry 8 million tonnes/year of products. The other pipeline will begin at Jinzhou, in northeast China's Liaoning Province, and carry as much as 4 million tonnes/year of oil. The two lines will meet in Zhengzhou, in the central province of Henan. A planned extension will reach Changsha, the capital city of Hunan Province, south of Henan.

The pipelines will transport oil from refineries handling crude oil received by pipelines from Kazakhstan and Russia.  In December 2005, line-fill began on the 614-mile, 32-in. crude oil pipeline between Atasu in northwestern Kazakhstan and Alashankou in China's northwestern Xinjiang region. The Chinese-Kazakh pipeline will initially carry 10 million tonnes/year of crude, with much of it expected to come from the Kumkol fields in south Kazakhstan and Chinese-owned oil fields in the Aktobe region of western Kazakhstan. China and Russia are discussing another pipeline project that would transport about 30 million tonnes/year of oil. The would extend 1,500 miles from Angarsk, Russia, to Daqing in northeast China's Heilongjiang Province.

Russia moves to protect oil fund from seizures abroad 

January 19, 2006. The central bank could soon take over management of Russia’s growing oil fund to secure it from possible legal action abroad. The ministry manages the fund, which collects crude oil export duties and extraction taxes above a cut-off oil price of $27 per barrel, keeping it in rouble accounts in the central bank. A year ago the government backed a conservative strategy to invest the fund, which reached 1.24 trillion roubles ($43.85 billion) this month, in AAA-rated securities denominated in US dollars, euros and sterling, asking the finance ministry and the central bank to work out the details. Since then the ministry has been at loggerheads with the bank, which is independent of the government, over the rules of the fund’s investment.

Ukraine seeks 25 year Turkmen gas deal

January 18, 2006. Ukraine is trying to establish a 25-year natural gas agreement with Turkmenistan as part of its effort to lessen its dependence on Russia for energy. Ukraine wants to have a direct contract with Turkmenistan to buy 20 billion to 25 billion cubic meters of gas. Ukraine depends on Russia for almost all its energy. It wants to diversify its supply, an effort that includes exploring for oil and gas in such countries as Kazakhstan, Egypt, and Libya. Ukraine, with 47 million people, consumes 76 bcm per year. It will get half of that from Turkmenistan this year. Ukraine agreed on Jan. 4 to pay an average $95 per 1,000 cubic meters of Russian gas, compared with the $230 demanded by Russia and the $50 Ukraine had paid previously. The agreement resolved a dispute that culminated in Russia's cutting off gas deliveries to Ukraine Jan. 1-3. Gazprom will supply Ukraine with gas through Rosukrenergo, a Swiss company.

Power

1000 MW gas power plant in Iran

January 23, 2006. A 1000 MW gas power plant is to be built in Khorramabad. Construction works for building the power plant is planned to start late this year and will be completed within a four-year period. The building of the power plant will be carried out through investments made by the private sector. Given that the building of the power plant is the first of its kind in the region, the huge project is expected to attract significant amounts of investments by the private sector. With the development of industries at the national and provincial levels the growing needs for a stable energy source has justified the building of the power generation plant in this western Iranian province. The power station is expected to address the energy needs of the region.

China ranks second in installed power capacity 

January 18, 2006. The total installed capacity of China’s power plants has reached 508.41 gigawatts at the end of 2005, ranking second in the world after the United States. China’s power supply has witnessed rapid growth in recent years since the country launched the west-east electricity transmission plan which aims to transfer power from the hydropower-rich southwest to the economically booming eastern provinces. In 2005, China’s total power consumption reached 2.47 trillion kwh. The transmission project contributed nearly 10 per cent of this. China’s electricity regulatory body will continue to back the project through the optimum allocation of resources and effective management of power plants across the nation.

LS Power signs coal plant contract

January 17, 2006. Plum Point Energy Associates LLC signed a contract with Plum Point Power Partners for the engineering, procurement and construction of its pulverized coal plant in Arkansas. The 665 MW pulverized coal plant, located in northeast Arkansas, will provide reliable, low-cost electricity to wholesale purchasers utilizing pulverized coal boiler technology. Plum Point Energy Associates is finalizing arrangements with a number of municipal utilities, electric cooperatives and other entities for joint ownership in the project and/or long-term power sales agreements.

PNM to buy Texas power plant

January 18, 2006. PNM Resources Inc. will buy a 305 MW, coal-fired power plant in Texas from Sempra Energy for $480 million in cash, in a bid to expand its merchant generating fleet. In addition to buying the Twin Oaks power plant, which is about 150 miles (241 kms) south of Dallas, PNM will also assume several of the plant's contracts. Under current agreements, the majority of the plant's output is sold for the next five years.

UK launches energy review in face of global warming 

January 24, 2006.  The British government launched an urgent public consultation on future energy policy but was accused of using it as a smokescreen to cover a decision already taken in secret to build new nuclear power plants. Highlighting Britain’s dwindling oil and gas supplies from the North Sea and the urgent need to cut carbon emissions in the face of global warming from burning fossil fuels. One-third of electricity generating capacity could go off-line over the next 10 years, three-month public consultation process that will report by mid-year. Johnson highlighted the disruption to gas supplies over the turn of the year when Russia turned off its pipeline that runs to Europe through Ukraine and said that by 2020 Britain could be importing 80 percent of its gas.

Metrobank to bid for Napocor power plants

January 24, 2006. Metropolitan Bank and Trust Co. (Metrobank), the Philippines’ largest lender, plans to bid for some of the generation assets of the National Power Corp. (Napocor) in the Visayas area in central part of the country. An estimated $1 million in investments is needed for the acquisition or establishment of one megawatt of power-plant capacity. In 2004 the Metrobank group, through Global Business Holdings Inc., teamed up with Mirant Philippines to acquire the 72-MW Panay Power Corp. through the joint venture Mirant Global Philippines Corp.  The acquisition of Panay Power in 2004 boosted the group’s earnings to a record-high of P1.4 billion. The local unit of US-based Mirant is the Philippines’ largest private producer of electricity, operating over 2,500 MW of generating capacity. Two projects are now in the pipeline- a 5-MW project and another 7.5 MW facility, both in Aklan province.

Indonesia may cut coal exports

January 24, 2006. Indonesia - which led a surge in global coal production last year - may cut shipments in 2007 because of increased domestic demand as it builds power plants to ease an electricity shortage. The country might export 5 per cent less than the 122 mn tonnes forecast this year. Producers are going to be supplying more to the domestic market, where demand is surging because three new power plants are starting up this year.

Local consumption may reach 35per cent of total output next year compared with 30per cent this year. Japanese power generators might have to pay higher prices for Indonesian coal next year to secure supplies.Indonesia has doubled shipments since 2000 and last year overtook Australia to become the world's biggest coal exporter to utilities. BHP Billiton, Rio Tinto Group and other coal producers in Indonesia, Australia and South Africa increased spending to expand their mines after coal prices soared in 2005, led by China's rising consumption. Demand for coal gained as crude oil and natural gas prices rose to records.

Ukraine and Russia discuss N cooperation

January 23, 2006. Ukraine and Russia aimed at expanding cooperation in nuclear energy, amid Kiev's interest in producing its own nuclear fuel for power plants. The talks focused on a new five-year agreement over the supply of atomic fuel to Ukraine. Ukraine currently has four operating nuclear power plants that produce about half of its electricity production, but it depends on Russia for fuel. Ukraine start to consider enriching its own uranium to produce fuel. The proposal is part of Yushchenko's effort to increase Ukraine's energy independence following a bitter dispute with Russia over natural gas prices. Ukraine currently supplies Russia with raw uranium and then buys it back after enrichment.

UAE to help research into nuclear energy

January 19, 2006.  The UAE and the European Organisation for Nuclear Research joined forces to further research in the field of high-energy physics. The agreement covers joint scientific and technical collaboration in the field of high energy and particle physics. It will allow UAE research centres and universities, including the UAE University, to initiate mutual research collaboration with CERN. The agreement would also enable UAE institutions to train its technical staff and students and to participate in postgraduate studies and use CERN's unique laboratory facilities.

Peabody to develop new coal mine in New Mexico

January 19, 2006. Coal miner Peabody Energy will develop a mine in northwest New Mexico to serve a 19-year, 65-million-ton coal supply agreement with Pinnacle West Capital Corp. subsidiary Arizona Public Service Co. The contract is expected to generate more than $1 billiom in revenue. Capital investments are expected to total approximately $90 million during the development period beginning during the fourth quarter.

Excel signs Taiwan coal supply contracts

January 18, 2006. The Wambo coal mine in the NSW Hunter Valley has signed a contract with a power company in Taiwan to supply three million tonnes of coal over the next six years. Mine owner Excel Coal has also signed another contract to supply international trading group Cargill with almost two million tonnes of coal over the next three years.

SK Corp. wins coal deal in Australia 

January 19, 2006. SK Corp., the country's largest oil refiner, and state-run Korea Resources Corp. won approval for coal exploration in the Australian state of Queensland. The two companies will secure final exploration rights for the Taroborah coal mine after submitting an exploration plan by Jan. 20. The deposit is estimated to hold about 300 million metric tons of soft coal. It will be the country's first fully-owned project in Australia. The two companies each hold a 50 per cent stake in the project and will spend a total of $150 million. The government hopes the project could lead to approval for other development rights and raise the country's self-sufficiency in the coal industry from 69.9 million metric tons, or 22 percent of demand, to 88.3 million metric tons, or 27 percent, by 2008. Korea is aiming to supply 35 per cent of its own demand, or roughly 94 million metric tons, by 2013. The two companies plan to complete exploration by 2009 and begin developing the mine in 2012. The coal will be used for power plants.

Mysore firm to produce biodiesel

January 23, 2006. A $10 mn biodiesel production facility and an international Jatropha technology centre will be set up in Mysore. A joint venture of the US-based Biodiesel Industries and Mysore-based Labland Biotech, the MoU was signed in Mysore for the two projects. The biodiesel production facility will be a model one, its technology based on the recently-patented Biodiesel Industries Modular Production Unit (MPU). It is expected to have the capacity to produce 10 million litres per year. The technology centre will be a state-of-the-art R&D facility. While the R&D facility will start functioning in about six months, the production facility will be ready for commercial production by December. The venture will be the first truly-integrated biodiesel project in India, which includes all aspects of jatropha research, development and cultivation, together with processing equipment for extracting the oils and converting it into biodiesel, meeting strict international standards. The advantage of the new MPU design of the oil refinery is faster and less expensive to prefabricate biodiesel production equipment at a central location and then install it in the area from where it will be operated. The MPUs are designed such that it can be transported by truck, rail or ship anywhere in the world. It is estimated that one biodiesel production facility based on the Biodiesel Industries’ MPU will provide jobs for over 20,000 families of farmers.  Another key feature of the MPU is that it can process a wide variety of feedstock into biodiesel, meeting the most stringent of US. and international standards. The feedstock could be virgin, crude and recycled vegetable oils and animal fats, such as soy, canola, mustard, rapeseed, fruit piths, cotton, palm, coconut, jatropha, neem, pongamia, hog fat, poultry fat, beef tallow, fish oil, recycled fryer oil and grease trap materials.

BHEL commissions solar plant in Sunderbans

January 20, 2006. THE Bangalore-based electronics division of Bharat Heavy Electricals Ltd has commissioned one more 110-KWp standalone solar photovoltaic (SPV) power plant in the backward Sunderbans in West Bengal. This is the fourth of five solar plants to be installed by BHEL for the West Bengal Renewable Energy Development Agency in this region. So far an SPV plant each of 55 and 105 KWp have been set up at Mousuni Island in the Sunderbans and a 110-KWp plant at Rakalpur in Sagar Islands. BHEL has also supplied pre-paid energy meters to the local families.

Tamil Nadu Newsprint to foray into carbon trading

January 20, 2006. Tamil Nadu Newsprint & Papers Ltd (TNPL) company is all set to enter into carbon trading after having got its bio-methanation plant registered as Clean Development Mechanism (CDM) project with UNFCCC (United Nations Framework Convention on Climate Change). The Certified Emission Reduction (CER) accumulations up to March 2006 is likely to be around 90,000 and the potential annual generation is estimated at 35,680 CER. The bio-methanation plant was set up in 2003 to generate methane rich bio-gas from bagasse wash water. The project was supported by the ministry of non-conventional energy sources as a demonstration project for high rate bio-methanation using pulp and paper mill waste water. By this process, the company generates about 15,000 M3 of bio-gas every day. The gas is being utilised in the lime kiln to partly replace the costly furnace oil to the tune of 8-10 kilolitre a day. Besides resulting in the reduction of fossil fuel consumption, the project helps in reducing the methane gas emission to atmosphere, which has high global warming potential (21 times than that of carbon dioxide). It is estimated that the company’s project can generate 35,860 CERs annually. Following the registration with UNFCCC and the project already in operation, the company is exploring the possibilities of trading CERs to developed countries. 

RSCL registers its cogen plant with UNFCCC

January 18, 2006. With the capacity expansion of its Mundiampakkam sugar mill on the anvil, Coimbatore-based Rajshree Sugars and Chemicals Limited (RSCL) has registered the company’s co-generation power project at Mundiampakkam unit under the CDM Project Activity with the United Nations Framework Convention on Climate Change (UNFCCC). This will enable the company to get 80,157 Certified Emission Reductions (CERs) in a year. RSCL has two modern integrated sugar complexes in the state. The Mundiampakkam unit, which was acquired by the company from South India Sugars Ltd in 2002, will see a capacity expansion of 5,000 TCD from the present 3,500 TCD. The co-generation plants have a combined installed capacity of 34 MW, the Theni plant having a capacity of 12 MW and the Mundiyampakkam plant having 22 MW capacity. These units generate green power using bagasse as fuel. After meeting the captive requirements, surplus power of about 18 MW is exported to the state grid. 

Solel signs $10M solar power contract

January 17, 2006. Solel Solar Systems ltd., a world leader in solar thermal technology for central power generation, signed a $10M contract with U.S. firm Solargenix Energy. Under the contract, Solel will supply Solargenix Energy with its unique solar receivers and thermal conduction units. Solargenix, a relatively new player in the solar energy field, will purchase the receivers and thermal conduction units which are key solar power generation components, to produce and supply pollution-free power for over 150,000 Nevada consumers. Solel is currently the world's sole provider of this solar thermal key equipment.

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