MonitorsPublished on Nov 15, 2005
Energy News Monitor I Volume II, Issue 21
Global Oil Trading: Mechanisms and Lessons for Risk Management

By Dr. Samir R. Pradhan*



ver the last three decades after the oil crisis, world oil trading mechanism has witnessed dramatic changes and transformations. This has been basically facilitated through the integration of world oil trading with the increasingly sophisticated global financial market in general and the advent of derivative securities for oil and other petroleum products in particular. Prior to that, much of the oil market was dominated by long term contracts with oil companies. However, the efforts of the oil producing countries and OPEC members to control oil supply during their hey-days of 1970s led the transition from long term deals to spot market trading. In addition, with the trend towards short-term spot trading, risk and uncertainty regarding the movement of equilibrium oil prices became a prominent feature of the world oil market. It is to be noted that, paradoxically, derivative contracts on oil and products became an integral part of the world oil market during the scenario of attempts to fix prices by major oil producing countries. In 1979 in the aftermath of the Iranian revolution, OPEC agreed to lift oil prices to $ 32 per barrel. Having such a target price would typically reduce the desirability of trading futures and options, since there would be little profit incentive for traders to take positions on which direction the market was heading. However, attempting to establish a floor price at an unsustainable high level set off such huge turmoil and price volatility in the oil markets, that the value of futures, options, and relative derivative contracts became important for the oil industry. Thus, it was with the development of spot trading, along with the surrounding uncertainty in the petroleum markets during the 1970s, that in turn led to the successful development of derivatives on petroleum products that has drastically changed the contours of world oil trading mechanism.

This four-part article intends to analyze the mechanism of oil trading through derivatives in order to manage risks in the highly fluctuating world oil market. Attempts will be made to analyze the implications of various forms of risk management through derivative trading for an emerging major oil importer like India and how the companies can adapt to the new techniques of risk management. With the proposed initiation of commodity trading practices of natural gas in states like Gujarat, these issues pertaining to derivative market and their importance to oil and gas market need to be analyzed in order to assess the feasibility of these modern techniques in dealing with price volatility.

Risk and Derivatives in Oil and Gas Market: Concepts, Types, Mechanisms and Roles

All forms of businesses face various types of risks, which can be generally classified into five different categories: market risk, (unexpected changes in interest rates, exchange rates, stock prices, or commodity prices); credit/default risk; operational risk (equipment failure, fraud); liquidity risk (inability to pay bills, inability to buy or sell commodities at quoted prices), and political risks (new regulations, expropriation). In addition, the financial future of a business enterprise can be dramatically altered by unpredictable events such as depression, war, or technological breakthroughs-whose probability of occurrence cannot be reasonably quantified from historical data (EIA, 2002).

Businesses in the oil and natural gas sector are susceptible to market risks particularly or more specifically, price risks-as a consequence of the extreme volatility of energy commodity prices. To a large extent, energy company managers and investors can make accurate estimates of the likely success of exploration ventures, the likelihood of refinery failures or the performance of any aspects pertaining to the industry. Diversification, long term contracts, inventory maintenance and insurance are effective tools for managing those risks. However, such traditional approaches do not work well for managing price risk. Commodity price risk plays a dominant role in energy industries and the use of derivatives has become common means of helping energy firms, investors, and customers to manage the risks that arise from the high volatility of energy prices.

Derivatives are financial instruments (contracts) that do not represent ownership rights in any asset but, rather derive their value of some other underlying commodity or other asset. When used prudently, derivatives are efficient and effective tools for isolating financial risk and “hedging” to reduce exposure to risk. Derivatives are particularly useful for managing price risk. Their use in energy arena is prevalent in all advanced countries, especially in the United State of America, Europe, etc. In such economies, energy derivatives are a natural outgrowth of market deregulation. Derivatives allow investors to transfer risk to others who could profit from taking the risk, and they have become an increasingly popular way for investors to isolate cash earnings from fluctuations in prices.

The asset that underlies a derivative can be a physical commodity (e.g., crude oil or rice), foreign or domestic currencies, treasury bonds, company stocks, indices representing the value of groups of securities or commodities or a service or even an intangible commodities such as weather-related index (e.g., rainfall, heating degree days, or cooling degree days, as used in countries like, the USA). What is important that the value of the underlying commodity or asset be unambiguous: otherwise, the value of the derivatives become ill defined.

Derivative securities come in various classifications. The various derivative instruments those can be used to isolate and manage risk can be analyzed under the following heads: forward contracts, futures contracts, options, and swaps.

(to be continued……)



Privatising Power Cuts?

“In field studies of SEBs, the investigator is struck by a situation that is a priori paradoxical. Let us illustrate this through an example, to be generalised in the book. In certain States the frequency of power cuts is explained by the fact that the distribution transformers often ‘burn’. There are not enough of them, and the ones in the network are overloaded. Hence the need for frequent repairing.”

‘There is ostensibly lack of funds for buying new transformers’, ‘there are political orders to devote resources to other fields’, are the explanations advanced. And yet… hundreds of damaged transformers are strewn on the ground. There may be tens of thousands at the scale of a State, They are not seriously damaged, at times it would suffice to change the oil, at the worst to rewind the coil. Put on the network at allow cost, they would instantly cut down most of the power cuts, smoothen the peak demand over a larger number of transformers, and thus would cut the future need to repair and ultimately save money! It is thus ‘profitable’ form an overall point of view. It has what economics call a social benefit, but it would as well bring a benefit to the SEBs, since the minimal ‘investment’ is very quickly recovered through future savings on (no longer burning) transformers.”

Excerpts from the book Privatising Power Cuts?  By Joel Ruet

The Political Economy of Power Sector Reforms:


Introduction to Issues and Expectations- Part II



eclining costs, liberal state financing, and exponential growth in demand continually reinforced the state’s role in the sector. Even as troubles arose—with unique origins in each country—the institutions that became entrenched around power made it easier to perpetuate the system rather than contemplate reform. In most cases, the impetus for reform arose from a crisis that created unavoidable problems as well as the political context for reformers to advance their agenda. In large developing countries (LDCs) crisis arose in the financing of the system—as economies of scale no longer delivered reductions in cost and as the inefficiencies of state control and financing mounted, the lights literally went out on the old model and presented an urgent need for change.

In the face of these financial crises, even creative accounting and soft budgets that had been used to prop up the system could not be sustained. In South Africa, excess power capacity delayed the onset of crisis—even there, a decade later than the rest, demand is outstripping available electric supply and the pressure for reform has reached a fever pitch. They are rich histories that are valuable in their own right.

The first issue is that the State Electricity Boards (SEBs) are difficult to reform because they are constructed of many interlocking elements. For example, it is commonly known that SEBs operate with “soft” budget constraints—that is, state financing—and that the central role of the state extends typically to political control over key appointments. Reformers typically aim to rectify this problem by transforming the SEBs into a corporation (even if wholly owned by the state) and imposing a hard budget constraint. In practice, such reforms can be neutered by the lack of complementary reform in accounting standards and corporate governance—the SEB simply reproduces in the “corporate” mode rather than the “state” mode the same conflicts of interest and lack of attention to performance that were pervasive. In some cases, reformers have been able to introduce elements of corporate efficiency without taking on all the interlocking elements of the SEB system. For example, many countries have created opportunities for independent power producers (IPPs) to generate electricity alongside the existing state enterprises, and the experience with IPPs has been highly variable. Often the IPPs merely perpetuate, with different nameplates, the state-dominated system; on occasion, they create benchmarks for performance and even niches from which wider private influence on the power system can evolve. The result of reform efforts is to create what is now being called a “hybrid market”—part state and part private.

Second is the issue of what motivations that reformers cite as their inspiration. In some cases the ideology of markets has played a contributing role, and in a few instances the multilateral development banks—notably the World Bank—have offered substantial financial and intellectual resources to key states, provinces and whole countries only on condition that they adopt market-oriented reforms. In India, China, Brazil, Mexico and South Africa the principal driving force for reform has been financial. Even in cases where reformers have held the reins of power, substantial reform has rarely followed until the state-dominated system is bankrupt and the lights are dimming. The financial motivation for reform affects outcomes—leading, for example, to a preference for the relatively easy goal of attracting IPPs while delaying the more sensitive task of unbundling the bureaucracy and inter-locking functions of SEBs that would be needed to apply reforms that are closer to the standard textbook model.

Of course, the financial health of the IPPs nonetheless depended critically on the yet incomplete broader reforms. What is truly extraordinary is that investors proved willing in the 1990s to pour billions of dollars into these markets with the faith that those delayed reforms would be favourable to their interests—despite the decades of earlier experience and careful scholarship on expropriation and squeezing of foreign investment on infrastructure projects such as power plants.

Because finance is a driving force for reform, the financial health of the sector, including analyses of the relationship between tariffs and costs become important. A key task for reformers is to raise tariffs. New fuels (notably gas) and technologies are typically more costly than the incumbents—in part because the incumbents were financed on soft budgets, in part because fuel markets often had subsidized prices (which reformers, too, are seeking to unravel), and in part because the power sector is facing new demands such as pollution control. An additional need for lifting tariffs is the long history of politicizing tariffs—in democratic countries, especially, politically powerful groups have been able to grasp the levers that control tariffs.

When economies of scale kept costs in decline and when electrification was not widespread these inefficiencies were not rampant; from the 1970s, however, both factors have largely evaporated—success in electrification and the end of the ever-larger-and ever-cheaper massive power plants have conspired to create a huge gap between revenues and costs.

The third core aspect is the institutions that must be created if the market (rather than the state) is allowed to determine prices and patterns of investment. We give particular attention to regulators. Just two decades ago, no large developing country had an independent regulatory authority. Today, regulators with formal independent powers exist in most countries.  Here the legal and institutional origins of the regulatory authorities, factors that explain whether and how regulators have true influence—the personnel who staff these authorities, the powers for decision making, and the powers for gaining information are important. Whereas much of the effort through regulatory assistance programs has focused on creating the fabled “independent regulator,” the formal conditions for independence are at best a necessary but not sufficient condition. Particularly absent in these new regulatory authorities are the powers needed to gather information that is the keystone to effective tariff orders and market oversight.

Fourth, is the issue of handling the consequences of reform for a wide array of social missions—or the “social contract” of the electric power industry.  In the old state-dominated system a wide array of public pressures and social mandates were built into the power system—tasks such as supplying electricity to low-income users particularly in India.  The massive changes implied by reform could threaten this “social contract;” indeed, many consumer and development groups have opposed reforms precisely because they fear this outcome. In the advanced industrialized countries there is considerable evidence that at least some of those fears have been realized—spending on R&D, for example, appears to have declined precipitously with the onset of market forces. Spending on environmental protection and social programs, too, have been exposed to greater transparency and exposure to market forces. In developing countries this social contract is being constructed and then re-constructed as the power sector is reformed to allow a greater role for market forces.

With a few exceptions, developing countries show little evidence of making much investment in R&D, either before or after reform. In the areas of electrifying the poor and protecting the environment, market reforms are correlated with better performance on the social contract and there is little evidence that reform has undermined the contract. In many cases, where reform seems to yield power systems that are financially more sustainable the reform process may actually make possible a much greater investment in this social contract. 

Edited and adapted from a paper by Thomas C. Heller and David G. Victor







CBM from Raniganj starts flowing

November 15, 2005. The decks were cleared for the extraction and sale of coal bed methane (CBM) from the Raniganj coalfields in West Bengal. Great Eastern Energy Corporation (GEEC), a part of the YKM Holdings Group is a major player in the commercialisation of technology for exploration and development of CBM. It has signed first commercial arrangement with Calcutta Compressions and Liquefaction (CC & L) recently for the sale of CNG in the industrial towns of Durgapur and Asansol. The CBM reserves were located in the Damodar river valley which stretches from Jharkhand to West Bengal. The gas-in-place was estimated at 1.385 TCF. GEEC would be among India's first private sector company to venture into coal bed methane exploration and production.

OMEL bags Nigerian oil blocks

November 14, 2005. Nigeria has awarded ONGC Mittal Energy Ltd deep water oil exploration blocks with a potential of producing 650,000 barrels per day (bpd) for the next 25 years. It also offered an assured supply of 120,000 barrels of crude per day, including 40,000 barrels per day lifted by the Indian refineries at present. In exchange, OMEL plans to invest $6 bn (Rs 274 bn) in Nigeria on 2,000 MW coal- or gas-based power plant, railway systems and capacity building. The company has also proposed setting up of an export-oriented refinery in Nigeria with a capacity of 180,000 bpd. Nigeria has assured of substantial liquefied natural gas (LNG) offtake out of the government’s share. The Indian venture’s investments will be proportional to the scale of oil discoveries under the agreement. The oil exploration blocks are yet to be identified. OMEL will also facilitate the upgrade of petroleum training institute at Effurun, Delta State. The company will also develop required trading, shipping and terminalling facilities in Nigeria. 

Selan signs gas prod sharing with MoPNG

November 11, 2005. Selan Exploration Technology Ltd has signed a production sharing contract with Ministry of Petroleum and Natural Gas for the Karjisan gas field in Gujarat. The ministry has now granted petroleum licence (PEL) to the company for the Karjisan gas field.

Norwegian major to bid for RIL's KG basin block

November 10, 2005. Aker Kvaerner, a Anglo-Norwegian engineering and construction major, will submit the gas production master plan to Reliance Industries for the latter's KG D6 project, by January 2006. The gas discoveries in KG D6 block are located at depths of 400-1,800 metres and are 35 km off the Andhra coast. Aker Kvaerner has relevant expertise in deep sea oil & gas production projects. The master plan involves the method in which the gas would to be brought onland, depending upon the pressure and contamination of the gas. It also involves the methods for separation, compression and storage of the gas, once it reaches the shore. The exploration and identification of oil wells has already been completed. RIL is soon expected to invite bids for the production project. Kaverner will be one of the bidders. Reliance has targeted the completion of development of D6 block by 2008-09 and commercial production by 2009-10. In the first phase, the company expects to extract 40 million cubic metres per day of gas production.


IOC cancels West African buy tender

November 11, 2005. IOC has called off a tender to buy up three Very Large Crude Carriers of West African crude for lifting between late December and January. The refiner last bought via tender a Very Large Crude Carrier (VLCC) of Nigeria's Bonny Light crude at a premium of $1.50-$2.00 (Rs 82-91) a barrel to dated Brent for loading in January. IOC, whose total refining capacity stands at around 1 million barrels per day (bpd), issues tenders several times a month to buy crude, mainly West African grades. The refiner purchased under a spot tender 2 million barrels of West African crude -- Bonny Light and EA grade – for loading in December at premiums of $1.80 (Rs 82 ) a barrel to dated Brent. 

IOC sets up Euro-III unit

November 9, 2005. IOC has set up a new unit to produce low-sulphur petrol at its 120,000 barrels per day (bpd) Haldia refinery. The refinery can now produce 0.35 mtpa, or about 8,100 bpd of petrol conforming to Euro-III standards, which allow sulphur content of 150 parts per million (PPM). Fuel from the refinery will also have lower levels of pollutants such as benzene and olefins. The project to make cleaner petrol was implemented in 18 months at a cost of Rs 3.59 bn ($78 mn). Haldia is IOC's second refinery to achieve 100-per cent production of petrol conforming to Euro-III equivalent specifications. IOC set up an isomerisation unit at its 150,000-bpd Mathura refinery in June and is scheduled to complete a project to make low-sulphur petrol at its Koyali refinery by June. India introduced strict rules for low-sulphur transport fuels in April, forcing refiners to import petrol and diesel since January as quality upgradation projects were delayed. Indian refiners are now producing enough low-sulphur transport fuels, reducing imports of clean fuels. 

PLL Kochi terminal to go on stream in 09

November 9, 2005. The much-delayed Rs 2,000 crore ($437 mn), 2.5 mmtpa Petronet Kochi LNG terminal is expected to go on stream by March 2009. The company would invite bids for EPC (erection, procurement and construction) works for the project by early 2006. The company has earmarked a sum of Rs 200 crore ($44 mn) to begin the Kochi terminal work. The terminal would be scaled up to 5 mmtpa at a later stage. Ras Gas of Qatar had agreed to supply the LNG for the terminal. The facilities in the terminal would include unloading arms, two tanks of 110,000 cubic meter capacity each, vaporisation system and utilities and off-site facilities. Petronet has already entered into fuel purchase deals with some string of power projects and a fertiliser firm in Kerala to supply LNG. GAIL had reportedly floated a separate pipeline to transport the gas from the project to distant areas.

Transportation / Distribution / Trade

GAIL signs MoA with Belgium's Exmar for new tech

November 10, 2005. Gail India Limited has signed a memorandum of agreement with Belgian shipping major EXMAR Marine NV for jointly pursuing projects and using the latter's on-board LNG regasification technology for LNG transportation by ship. The MoA will help transportation of LNG from Myanmar across Bay of Bengal to the east coast, most likely at Haldia or Paradip port. The on-board LNG regasification technology would reduce cost considerably when compared to the conventional re-gas facility.

The GAIL-Exmar venture would also help feed LNG required for Dabhol project, which is expected to be operational soon. The Minister further said that the agreement would also help rapidly conclude the Myanmar LNG import project. Under the MoA, GAIL will have access to the Exmar-developed new application, "LNGRV", which regassifies LNG and discharges it in various modes. The technology is currently in operation at the World's first offshore LNG Terminal at the "Gulf Gateway" operated by Excelerate Energy. Gail has already undertaken the study for use of this technology at three different locations such as Krishnapattinam in Andhra Pradesh, Hazira in Gujarat, Kerwalpitiya near Colombo. The agreement would enhance the bilateral between the two countries.

GEECL signs agreement for sale of CNG in WB

November 10, 2005. Great Eastern Energy Corporation Ltd has signed an agreement with Calcutta Compressions and Liquefaction (CCL) for the sale of CNG in West Bengal's Durgapur and Asansol cities. As per the arrangement, GEECL, which has expertise in the field of production of Coal Bed Methane gas from the coal seams, will supply CBM gas and also help CCL to complete the CNG project in WB. GEECL is already exploring for CBM gas in the Raniganj coalfields in the Damdor Valley near Ansol. GEECL would produce the CBM gas and transport the same to the group gathering station. The selling price of CBM gas to CCL would be $5  (Rs 229) per 1,000 cubic feet.

Policy / Performance

India to become refining hub: Secretary MoPNG

November 15, 2005. The policy direction of the petroleum ministry seeks to make India a refining hub in the coming decades. Apart from the expansion of the HPCL’s Vizag refinery in the state from 7.5 mmtpa (million metric tonne per annum) to 15 mmtpa, three more refinery projects — HPCL’s Bhatinda unit in Punjab, BPCL’s greenfield project at Beena in Madhya Pradesh and IOCL unit at Paradip in Orissa — accounting for a total of 27 mmtpa were in the pipeline. India’s total installed refining capacity as of April 2005 stands at about 127 mmtpa. Though the country is self sufficient in refining and surplus in most of the petroleum products, there is huge shortage of crude oil. About 75 per cent of the country’s crude oil demand is met through imports and the country is extremely vulnerable to various factors affecting the hydrocarbon sector. Oil refining, petrochemicals and gas processing in India has considerably increased in the recent past and the thrust was now on optimisation of the refining business to sustain growth and derive maximum benefit. The thrust on refining today is maximising value addition from affordable feedstock processing. The surplus refining capacity along with a growing demand for petroleum products have sustained healthy refining margins in India. The government of India had commissioned a study by Shell Global Solutions on the working of the refineries whose results would be made available by the end of the year.

Petroleum deals with 9 countries in the pipeline

November 15, 2005. With a view to securing its energy needs within the Asian community, India has lined up a series of bilateral agreements in the petroleum sector, to be signed next week with five Central Asian and three Asian countries, besides Turkey. The agreements would coincide with the second round table of major Asian petroleum consumers and sellers to be held on November 25. The round table will this time focus on the north and central Asian countries. It will also focus on an “intra Asian dialogue” for stability, security and sustainability in the oil sector. The round tables are part of India’s vision to take the major Asian consumers along in its quest for hydrocarbon resources, though the first one did not bring any tangible gains regionally. India was laying emphasis on Turkey’s participation in the coming round table even though it did not come under the identified geographical area. Turkey is the transit point for oil and gas headed for Europe. It also plays host to a number of transnational pipelines, the latest addition being the Baku-Tbilisi-Ceyhan (BTC) pipeline. Significant bilateral meetings in terms of tangible gains for Indian oil companies were likely to be signed with Uzbekistan and Azerbaijan. India was interested in the gas potential of Uzbekistan which could become the gas source for the region with an estimated reserves of 66.2 trillion cubic feet. Azerbaijan also had old refineries which Indian refiners could be interested in modernizing. The buyer nations, which comprise India, China, Japan and Korea, would remain the same for the forthcoming round table, though on the seller side there would be participation from Russia, Kazakhstan, Turkmenistan, Uzbekistan, Azerbaijan and Turkey. The countries were likely to be represented by their energy ministers., though in some cases it could also be deputy ministers. India was likely to initiate five agreements with Korea. In the case of Japan, the focus would be on technology, research and development, safety, strategic storage and LNG facilities, besides pipelines. With Turkmenistan, India was already taking part as an observer in its pipeline to Pakistan via Afghanistan.

Text Box: •	Significant bilateral meetings in terms of tangible gains for Indian oil companies likely to be signed with Uzbekistan and Azerbaijan 
•	India is interested in the gas potential of Uzbekistan which, could become the gas source for the region with an estimated reserves of 66.2 trillion cubic feet 
•	Buyer nations will comprise India, China, Japan and Korea, and seller side will have Russia, Kazakhstan, Turkmenistan, Uzbekistan, Azerbaijan and Turkey 
Aiyar`s plan to open oil blocks hits hurdle

November 14, 2005. Petroleum minister Mani Shankar Aiyar’s “inward diplomacy” proposal, urging international oil companies to invest in the domestic oil major’s nomination blocks, seem to have met with opposition from within ONGC. The ONGC maintains that more investments should be channeled into the unexplored sedimentary basins of the country. On the other hand, the government would open up the nomination blocks held by the ONGC for investment by foreign companies. The minister said the average recovery rate of ONGC was far below international standards and bringing in foreign partners would help matters on this front. 

The country has 26 sedimentary basins, of which the ONGC has made discoveries in five. Only one sedimentary basin had been discovered outside the ONGC-fold, at Digboi in the Assam Arrakan basin, by the Assam Railway and Trading Company in 1890. The government had granted production and exploration licences to the ONGC for about 114 blocks in the country when it was not a company but was Oil and Natural Gas Commission. A small number of blocks, mainly in the Assam Arakkan basin, were allotted to the other public sector player, Oil India Ltd. 

OIL-IOC referred to GoM for more financial muscle

November 13, 2005. OIL India Ltd and Indian Oil Corporation may have to wait longer before they get more financial teeth to acquire overseas exploration and production (E&P) assets. The Finance Ministry has sought some clarifications on the proposal. The issue has since been referred to a Group of Ministers. The Finance Ministry had opposed the move stating that this would create unnecessary competition for ONGC Videsh Ltd. This was despite the Petroleum Ministry inserting a clause in the proposal that would ensure that both OIL-IOC and OVL would not bid for the same blocks. The Finance Ministry is understood to be of the view that, instead of OIL-IOC joining forces, a special purpose vehicle (SPV) like OIL Videsh Ltd could be formed on the lines of ONGC Videsh. It has also said that OIL should look to be the strategic investor in OVL's overseas ventures. The Petroleum Ministry has suggested certain changes in its proposal, which will throw open the exploration sector for all oil public sector undertakings. The Ministry will propose that along with IOC, other downstream companies should also be allowed to partner with either OIL or IOC for such assets. The Petroleum Ministry had approached the Cabinet Committee on Economic Affairs for a fast-track approval mechanism for OIL-IOC to acquire overseas E&P assets. The Ministry recommended that the OIL-IOC combine be given investment decision-making powers on par with those of OVL for E&P ventures abroad.

Rural-urban ratio in LPG sale may go: Centre

November 11, 2005. To increase the role of new entrants such as GAIL India, ONGC and Oil India Ltd in LPG marketing, the Centre plans to waive restrictions on marketing in rural/urban areas. However, Centre is keen that the new entrants will have to adhere to an 80:20 ratio of domestic/non domestic sales (commercial and industrial). Currently, owing to the administered price regime, 80 per cent of their production has to be sold at a subsidised rate in the rural areas, while the rest can be sold in urban areas. This apart, 80 per cent of the production has to be sold domestically, and the rest to commercial and industrial establishments. The new entrants will have to adhere to the latter condition. The ministry said that if new entrants are prepared to market domestic LPG without any subsidy from the government then they are permitted to sell LPG at a price higher than the existing administered price. Centre has also proposed the upstream companies like ONGC, OIL and new entrants to undertake a pilot project of LPG marketing whereby they would decide the areas where they can take up marketing, to ensure that there is no disruption in supplies to the existing market.

MEA to tie up gas from Oman and Qatar for Ratnagiri

November 11, 2005. The high-powered committee on re-starting the Dabhol power project has decided to involve the ministry of external affairs (MEA) in tying up the availability of gas from Oman and Qatar for the Ratnagiri Gas and Power Private Ltd (RGPPL). A delegation headed by power secretary RV Shahi with senior officials from MEA and the petroleum ministry would shortly leave for Oman and Qatar to conclude the deal with LNG suppliers, including Oman Gas and Ad Gas. GAIL India Ltd has already been negotiating with the two companies for sourcing gas for the project. To ensure availability of gas for RGPPL, diplomatic support is required to leverage bilateral ties and to resolve pending issues.

Aiyar to discuss TAP with Pak

November 11, 2005. Petroleum and natural gas minister Mani Shankar Aiyar has invited Amanullah Jadoon, oil minister of Pakistan, for talks on Turkmenistan-Afghanistan-Pakistan (TAP) pipeline. Asian Development Bank (ADB), which will finance the project to help out Turkmenistan, is keen on an early meeting, while Pakistan says the steering committee should not meet until an independent certification of the reserves in the Daulatabad gas field are made available. Security measures and price of gas that India and Pakistan want to import are among the issues listed for discussion by the working group.

Myanmar pipeline back on course

November 10, 2005. The much delayed Myanmar-Bangladesh-India gas pipeline project would soon become a reality with India open to taking a more liberal view on the three issues raised by Bangladesh for signing the trilateral agreement on the gas pipeline project. On the issue of improving the trade imbalance between the two countries, the ministry of commerce has agreed in principle to provide increased market access to Bangladesh as a least developed country under the South Asian Free Trade Agreement and the Bangkok agreement. As there is no bilateral FTA/preferential trade agreement on which the trade between India and Bangladesh is based. On the other two issues, a joint press statement is likely to be arrived at between India and Bangladesh on the sidelines of the forthcoming South Asian Association for Regional Cooperation (Saarc) summit in Dhaka. The two issues are: transmission of hydro-electricity from Nepal and Bhutan to Bangladesh through Indian territory and on providing a corridor for supply of commodities between Nepal and Bhutan and Bangladesh through the Indian territory.

India expects $33 bn crude import bill this year

November 10, 2005. India's crude import bill in the fiscal year ending March is seen reaching Rs1.5 trillion ($33 billion, Dh120.43 billion) compared with Rs1.2 trillion a year earlier. State-run refiners Bharat Petroleum Corporation Ltd. and Hindustan Petro-leum Corporation Ltd. were likely to see their losses widen due to the recent additional imports of LPG.

The firms, already reeling from having to cap retail fuel prices despite steep crude prices, were forced to import more LPG mainly because of a shortfall of the cooking gas. Oil companies attributed the LPG shortfall to many factors, such as a partial shutdown of Reliance Industries Ltd.'s 660,000 bpd refinery in Jamnagar over eight weeks from October, fewer supplies from Oil and Natural Gas Corporation due to a fire which destroyed a major platform in July, and refinery upgrades.

Oilcos may have to share E&P data with DGH

November 9, 2005. The Director General of Hydrocarbons (DGH), who also doubles up as the upstream regulator, may soon be provided with the power to gather all exploration and production data held by exploration licensees. The DGH will also get to have a say in the overseas exploration and production strategies of state-run oil companies. Although it is not clear how the DGH will provide “inputs” this new dispensation will give the DGH more power over overseas operations of oil PSUs. The DGH will be empowered to access all E&P data from companies holding petroleum exploration licences (private, foreign, joint venture or PSU) or mining leases in respect of Nelp blocks or nominated/pre Nelp blocks. The petroleum ministry is of the view that several global oil majors have evinced interest in entering into partnerships with Indian oil companies in existing oil blocks. Sharing of data of existing blocks may work as a major facilitator in luring foreign global majors. This move is in line with the government’s plan to go in for an open acreage system, where oil companies can access the data of existing blocks and take up interests in existing producing fields. The government is planning to move a Cabinet note to increase the powers of the DGH with regard to exploration and production companies.

GAIL to expand global E&P portfolio

November 8, 2005. Domestic gas major GAIL (India) Ltd has decided to selectively develop a portfolio of global exploration and production (E&P) acreages. After Myanmar, where it has a 10 per cent participating interest in two offshore blocks (A1 and A3), GAIL has decided to pursue E&P opportunities in Indonesia, Australia and Sri Lanka. The company is in process to team up with an Australian oil and gas exploration company, Oilex, and submit joint bids for two exploration blocks in Western Australia. In addition, GAIL is also negotiating for picking up stakes in Oilex’s existing acreages in Australia, where it is the operator in nine blocks. Oilex too is targeting India’s energy sector and is keen to participate in the bidding rounds for gas blocks. It is also in talks for a 30 per cent farm-in opportunity in a Cambay basin block, awarded to Gujarat State Petroleum Corporation. The two blocks in Australia for which bids GAIL has submitted joint bids with Oilex as operator are WO5-16 (Exmouth Plateau/ Barrow Sub Basin in Northern Carnavron Basin) and WO5-3 (Northern Browse Basin). GSPC and Prize Petroleum (a joint venture between HPCL, ICICI Bank and HDFC) have also agreed to pick up 25 per cent participating interest in the two blocks. Australia has put 15 offshore exploration blocks on offer in the first round of auction. A separate MoU would soon be signed between GAIL and Prize Petroleum for jointly pursuing overseas E&P opportunities. Australian oil and gas exploration company, Oilex, has participating interest in 17 onland and offshore blocks in Australia. It had its first oil discovery in Surat Basin in Australia in 2005.



Vemagiri power plant begins trial production

November 14, 2005. The Rs 1,200-cr ($263 mn) Vemagiri power plant of the GMR group in Rajahmundry in Andhra Pradesh has begun its trial production. The actual commercial production will commence in January 2006. The installed capacity of the plant was 388 MW as against the contracted capacity of 370 MW. The machinery with advanced class gas turbine technology, which uses natural gas as fuel, was imported from the US. GAIL India has agreed to supply 1.64 mmscmd of gas as per the agreement. GMR has also entered into a power purchase agreement with APTransco. The Vemagiri power unit is the third project of the GMR group, the other two are GMR Power Corporation (200 MW) in Chennai and GMR Energy (220 MW) in Mangalore.

JP for major investment in power sector

November 13, 2005. Jaiprakash group would invest upto Rs 20,000 crore ($4.4 bn) in developing hydel and thermal projects by 2012 to emerge as one of the top three integrated power players in the country. It will put all power investment in JP Associate under a separate entity that could be its holding company for all its power sector ventures. It has already commissioned Ernst and Young for the restructuring exercise and will take a decision by April next year. With these investment plans it will become 5000 MW company from 300 MW now, in next five years. Having commissioned 300 MW Baspa-II successfully run by Jaypee Hydro Power Limited, which went public last year, the second project of 400 MW at Vishnu Prayag in Uttaranchal will come on stream in March 2006. Besides this the company has started pre-construction work at 1000 MW Karcham Wangtoo in Himachal Pradesh at an investment of over Rs 5,400 crore ($1.2 bn). All these three projects are being implemented through different subsidiaries of Jaiprakash Associated Limited. The Group has also been allotted two hydro projects for over 2100 MW in Arunachal Pradesh. Apart from these hydel projects, the company is also likely to undertake 1000-MW thermal project. It has also submitted a bid for a 500 MW coal-fired plant to Madhya Pradesh State Mining Corporation to form a joint venture for a coal mining project.

NTPC to set up power plant in Sri Lanka

November 9, 2005. Power major NTPC is looking offshore to expand its energy business. The company has submitted a proposal to the Sri Lanka to develop a 500-MW plant in the island nation. The project may be expanded to 1,000 MW. The proposal is a part of the bilateral talks between the two countries to work out a comprehensive economic co-operation agreement. The Sri Lankan government had evinced interest in investments in the power sector and other infrastructure areas. NTPC, which has taken up consultatncy for power projects in foreign countries, is now hoping to expand its business by creating greenfield power capacities in third countries.

NTPC, which has diversified into hydel power, is also planning to move on to nuclear power in the future. The company has recently tied up with oil majors to get into exploration of gas in India and is planning to take up interests in the LNG business abroad too. The single largest power company in the country, NTPC, plans to evolve as an energy major with business interests in the entire energy chain.

German bank to fund Krishnapatnam power project

November 9, 2005. The German bank, KfW, has expressed its willingness to lend Rs 3,600 cr ($787 mn) to APGenco for setting up a 1,600 MW mega thermal power project at the port town of Krishnapatnam in Nellore district. The loan amount is exactly half the estimated cost of the project. The first 800 MW unit of the project would to be completed by 2010. This is the second time that K f W has funded a thermal power project in Andhra Pradesh. The bank had earlier offered Rs 1,500-crore ($328 mn) to APGenco for establishing a 660 MW super critical thermal unit at the Vijayawada Thermal Power Station (VTPS). 

Transmission / Distribution / Trade

WBSEB aims 100 pc rural electrification

November 15, 2005. West Bengal State Electricity Board was aiming to achieve 100 per cent rural electrification by 2009. Total electrification would follow from the intensive implementation of the second phase of the rural electrification plan in the state. In the first phase, WBSEB provided electricity connections to at least 10 per cent of households in each village as well as to all the public institutions of that village. In the first phase, 32,000 of the 37,000 villages in the state were covered. The remaining 5,000 would be covered by March 2007. This would mean a cost of Rs 400 crore ($88 mn), 90 per cent of which would come from a central grant and the balance as a loan from the Rural Electrification Corporation (REC).

All J&K to be electrified by ’09

November 12, 2005. Aiming to provide electricity to every household in the state by 2009, the Jammu and Kashmir government has signed agreements for launching works on seven power projects and resolved to expedite the Baglihar and Sawalkote projects. Project reports have been sent to the Centre and the first phase work on two projects at Anantnag and Kupwara would begin soon. Over Rs 5 cr ($1.09 mn) would be used to augment transmission lines, replace electric poles and defective transformers in the state over the next two years. The state electricity demand stood at 1,800 MW against a supply of just 700 MW, which was upsetting plans to provide sufficient power to all the people. The state is currently purchasing power from the northern grid at a cost of nearly Rs 1,300 cr ($284 mn) annually.


Nagarjuna signs MoU with KSEB

November 10, 2005. The Nagarjuna Power Corporation Limited has signed an MoU with the Kerala State Electricity Board to supply power. Ten per cent of the power it produces will go to Kerala especially Kasargod district and the remaining 90 per cent will go to Udupi, Dakshina Kannada, and other parts of Karnataka. Karnataka Mescom will take the maximum power generated by NPCL. The tariff by the Company will be in the range of Rs 2.20 which is one of the lowest for any new power plant in the country. The company would use imported coal with 15 to 20 per cent ash. By the ninth year there would be cent per cent utilisation of the ash for different purposes. The project would use only sea water and there were no plans to extract fresh water from the river or any other sources

Policy / Performance

Pay attention to power, coal sectors: PM

November 15, 2005.  Prime Minister Manmohan Singh urged states to pay attention to power and coal sectors as shortage of power could handicap them critically in their quest for growth. He said that the trend of globalisation was irreversible and the government was committed to bringing tariffs down to Asean levels. The country is on the threshold of unveiling an India-Asean FTA and the Safta will come into effect from the coming new year. He said that improving availability of power at efficient prices was of prime importance for the government and for that there is need to improve the financial condition of power distribution companies. There is also need to focus on making state electricity boards (SEBs) viable, healthy and efficient.

C&O bags coal supply bid for Parli power plant

November 15, 2005. Coal & Oil (C&O), a Dubai-based coal supplier, has been awarded the contract to supply imported coal for the upcoming power plant at Parli in Maharashtra. The plant is expected to be synchronised in April 2006. The company, through its subsidiary Coastal Energy, has been awarded the contract to supply 600,000 tonne of bituminous coal following Maharashtra State Electricity Board’s (MSEB) 640,000 tonne tender for delivery. C&O has also offered multi-origin material for the Khaperkheda and the Parli plants in the state. This is the first time that MSEB has decided to use imported coal at Khaperkheda. Previously, imported coal has been used in the Nashik and Bhusawal plants. With all these plants depending on imports, MSEB’s coal imports will be around 2 mt in the current fiscal, up from just under 1 mt in the previous fiscal. C&O won the 0.9 mt supply tender for the Nashik and Bhusawal plants in March.

C&O, which already owns a coal mine in Indonesia, is also exploring the possibility of getting into coal mining in the country in partnership with power companies to whom it supplies coal, including Reliance Energy, Tata Power and Calcutta Electric Supply Co (CESC) and Gujarat State Electricity Board. Currently, barely 10 per cent of demand for coal in the country is met through imports. However, both the central and state governments have begun promoting imported coal-based plants located along the coast. MSEB has also plans of setting up a 1,000 MW coastal power plant at Dhopave in two phases of 500 MW each. 

Eastern region to become power hub in few years

November 14, 2005. The eastern region is all set to become a power hub in the country in a few years with 40-43 per cent of the total national investments earmarked for the creation of additional power generation capacities expected to be made in this region, largely in thermal and hydro-electricity projects. The power sector in the region had been neglected in the past due to inadequate transmission facilities. The region had vast reserves of power grade non-coking and water resources to support massive generation of thermal and hydro-electricity. Such hindrance had since overcome following the creation of transmission and distribution network throughout the country. Generating stations in the region have started exporting power to the power deficit States during off-peak hours at a premium tariff. The country had plans to augment power generation from 1,16,000 MW to 1,80,000 MW by 2011-12 which included a substantial portion from the eastern region. It is expected that major portion of generation from this region would be exported to the power deficit States.

10 pc of power from non-conventional sources mandatory: Govt

November 11, 2005. The government may soon make it obligatory on states to meet 10 per cent of their total power needs from non-conventional energy sources, including hydroelectric power. The move is part of efforts to build a large consumer base for non-conventional energy sources that has so far failed to take off in the country. The Planing Commission has given its nod to the proposal that will now form part of an integrated energy policy being framed by the energy coordination committee headed by Kirit Parikh. Once approved by all states, the proposed regulation would require states to increase the share of power from non-conventional energy sources (up to 10 per cent) in their total energy kitty. This could either be done by purchasing power from states having having surplus capacities in the non-conventional space or increasing their own greenfield capacities. Despite the government’s numerous initiatives, the popularity of non-conventional energy is low among consumers. The high cost of power from these sources is one of the main reasons for its low popularity.

It may be noted that the share of hydro power in the country’s total installed capacity of about 116,000 MW has fallen to 27 per cent. The share of other non-conventional energy sources like solar, wind, nuclear and small hydro projects is even lower. As the production of power from these sources is pollution free, the government wants to increase its share in total power kitty. The proposed government initiative may also fix a fixed percentage within the 10 per cent mark for non-conventional energy sources, excluding hydro power also. The move is expected to benefit West Bengal, Maharashtra, Uttaranchal and Himachal Pradesh, where production from non-conventional sources is already high. These states could now become net exporters of power to other states once the regulation is put in place.

India trade fair to focus on power

November 11, 2005. India International Trade Fair (IITF) beginning in New Delhi from November 14 for two weeks would put on display manufacturing and economic achievements of India and other countries over a broad sectoral canvas. The themes chosen for the fair were "power and communications" which hold immense potential in realising the high growth of the Indian economy.

Tamil Nadu draws draft on captive power tariffs

November 11, 2005. The Tamil Nadu Electricity Regulatory Commission (TNERC) has come up with consultation papers for purchasing power from captive power plants and for fixing tariffs for non-conventional energy sources. As far as captive power plants are concerned, excess power from these plants are sold to the grid at a tariff determined and fixed by the Tamil Nadu Electricity Board. The regulatory commission now hopes to come up with a formula under which the board would pay the captive power generator for the power it buys. The commission hopes to fix a floor and a ceiling for the tariff that the electricity board, or a distribution licensee, may pay to a captive power producer. That is, the purchase price will be high when the captive power producer supplies to the grid, when the grid needs power the most. Likewise, the purchase price will be low when the power is supplied to the grid at a time when the demand is low, but the electricity board or the distribution licensee is committed to purchasing power.

Tamil Nadu has seen a historical annual growth in energy consumption of five per cent to six per cent in the last 10 years. The State consumed 40,638 million units (MU) of power during 2004-05, when the gross generation was 52,345 MU. With a spinning reserve of 500 MW - Tamil Nadu's total capacity, including from Central generation stations, as on September 30, 2005, was 9,550 MW - the net deficit would be 629 MW in 2005-06 and the corresponding energy shortage 1,130 MU. The commission's draft paper on captive generating plants points out that there are 22 operational captive plants as on March 31, 2005, in the State with a total capacity of 432 MW. Five more captive plants with a total capacity of 297 MW are to be commissioned during this year. With the Electricity Act, 2003, providing opportunities for more captive power plants to come up, the commission notes that there is an opportunity to harness the excess saleable capacity with captive plants, which could be used to bridge the demand-supply gap. The rate of purchase of captive power shall be linked to the prevailing grid frequency and subject to a band of a minimum (floor) and a maximum (ceiling) rate of purchase. It has calculated this band as Rs 2.30 per unit to Rs 3.80 per unit. As far as non-conventional energy sources are concerned, the commission's draft discussion paper seeks views on setting tariffs. The electricity board now pays a fixed tariff — Rs 2.70 per unit for wind energy. The commission has also proposed a reduction in the transmission and wheeling charges for biomass and cogeneration projects. Biomass projects now attract transmission and wheeling charges of 10 per cent, which the commission's paper suggests can be reduced to 2 per cent for within 25 km of usage and 7 per cent for beyond 25 km of usage.

Capital in for power shock if tariff losses continue: NCAER 

November 11, 2005. According to a study conducted by National Council of Applied Economic Research (NCAER) on the Delhi power reforms, if the aggregate tariff and commercial losses are not brought down by the power distribution companies (discoms), the storm kicked off by the July tariff hike will reappear in a magnified form during the tariff revision, next year. NCAER has pointed out that the targets for the loss reduction set by the government for the discoms are too modest. The loss level to be achieved by New Delhi Power Limited (NDPL) and BSES Rajdhani Power Limited (BYPL) is 31.1 per cent and for BSES Yamuna Pvt Ltd (BYPL), the target is set at 39.95 per cent. It also points out that the subsidies offered by the government through “transfer scheme” would be inadequate to meet the revenue gap. In the transfer scheme, the government had decided to subsidise the Delhi Transco to the extent of Rs 3450 crore ($756 mn) through four pre-set yearly installments. The subsidy was provided to meet the gap between the bulk and retail prices, till the loss was brought under control. NCAER is of the view that it is facile to assume that the discoms would be able to meet their obligations without considerable added support.

Nuke power 10-fold by ’22

November 10, 2005. The nuclear electricity generating capacity of India would increase about 10-fold from the present 2.7 GW to 29 GW by 2022. Though the modest deposits of uranium (about 60,000 tonnes) cannot take the maximum installable capacity beyond 10 GW, large deposits of thorium – 360,000 to 520,000 tonnes – in the country would see India achieve a sustainable nuclear power generating capacity by 2040 as envisaged in the three-stage Indian nuclear programme. The first stage envisaged use of uranium and power generation primarily through pressurised heavy water reactors (PWHRs) and the spent material to build up inventory for the second stage – fast-breeder reactors (FBRs). The third stage envisages use of thorium and the inventory generated through the previous two stages.

Global bids soon for ultra mega power projects 

November 9, 2005. The power ministry plans to float global tenders inviting private sector to put in competitive bids for setting up four 5,000 MW ultra mega projects, which could be subsequently expanded to 8,000-10,000 MW. These would be hydro projects and pit-head coal and imported coal-based thermal projects. The four projects would entail an investment of about Rs 80,000 crore ($17.5 bn). The government would be a facilitator for the ambitious plan and help the developers with site identification, coal allotment, environmental sanctions and coordination with states for power purchase agreements. The power ministry, together with the Central Electricity Authority (CEA), was already in the process of selecting sites. It was simultaneously in talks with the coal ministry for captive coal allotment for the projects. The power ministry had already issued guidelines for competitive bidding under the Electricity Act, 2003. These projects would mark a shift from cost-plus based tariff regime to a competitive tariff regime.

According to the power ministry, the project developers would be required to enter into power purchase agreements with different utilities for the offtake of power. Such an arrangement was acceptable to Indian lenders and there would be no dearth of funds for these projects. This apart, the power ministry has convinced all states to invite expressions of interest (EoI) based on competitive tariff for development projects with 1,000-2,000 MW capacity. The ministry also proposes to open up transmission for private sector participation by allotting a certain portion of the national transmission grid to the private sector.

Eastern Coalfields to raise production

November 9, 2005. Eastern Coalfields Limited would increase its coal production from the level of 27.25 mt in 2004-05 to 43.74 mt in 2009-10 through a combination of capacity build-up and adoption of the state-of-the-art technology in underground and opencast coal mines. The company would augment the capacity and production at its open cast mines by expanding Rajmahal OCP from its present capacity of 10.5 mtpa. It would start up new opencast mines at Chupervita with capacity of 4 mtpa and Hura-C with 3 mtpa capacity. In addition, ECL had identified three new projects for the coming years. The Sonepur Bazar mine expansion would be completed to take production from 3 mtpa to 8 mtpa.The Chitra mine expansion project will take output from 1.2 mtpa to 2 mtpa. The highwall mining project at at Sripur and Nimcha block would secure production of 3.2 mt. Three new underground projects at, Naba Kajora and Kumardih-A would simultaneously be developed, which would together give additional production of 1.38 mtpa. 

IFC identifies energy sector for investment in India 

November 8, 2005. The Washington-based International Finance Corporation has identified three sectors, energy, bio-technology and pharmaceuticals, and ports in India for its future endeavours. The private finance arm of the World Bank will be participating through equity or aid. IFC has made a combined $49 mn (Rs 2.2 bn) loan and equity investment in AD Hydro Power Ltd in the Himalayas of northern India. IFC’s funding supports construction, operation and maintenance of a 192-MW run-of-the-river hydroelectric power plant and a 185-kilometer, 220 kilo-volt transmission line.




Big Sky Energy starts production in Kazakhstan

November 15, 2005. Big Sky Energy Corp. started production from its Karatal Block on the Caspian Sea north shore. It placed Well 6, reentered and worked over earlier this year, on production at 100 b/d of oil from a Jurassic formation at 591-596 m. The company mobilized a rig on the block and plans to drill new wells and rework others. Well 30 is to spud within 15 days and go to TD 800 m to test Cretaceous and Jurassic sediments. Big Sky identified this and other locations on 2D seismic data acquired earlier this year. This Well produces on pump to a well site oil battery. Oil production is sold at the field under a short-term sales contract.

Norway Govt: 5 bn boe undeveloped oil, gas finds

November 15, 2005. Around sixty oil and gas discoveries on the Norwegian Continental Shelf, representing almost 5 billion barrels of oil equivalent, have yet to be developed. Of those, around twenty discoveries is expected to be developed in the next five years, the equivalent of 1.90 billion boe. Around 1 billion boe, or 162 billion cubic meters, of that figure will be natural gas. 


Several finds will need more appraisal wells while other finds are too small to develop without established infrastructure near by. The NPD estimates there are around 21.4 billion boe undiscovered on the Shelf, fairly evenly split in the North Sea, Norwegian Sea and the Barents Sea. The Govt received applications from 24 companies for blocks in the 19th oil and gas licensing round. The concessions -focusing on the Norwegian and Barents Seas - will be awarded in the first quarter of 2006.

Nigeria asks Russian companies to invest in oil & gas sector

November 15, 2005. Nigeria, which ranks sixth in the world in terms of oil production, has called on Russian companies to invest in its oil and gas sector, in particular, to search for and develop new hydrocarbon resources on its territory. Nigeria has a rapidly developing economy and would offer investors advantageous terms for working in various branches of the economy, such as the oil and gas sector, the agro-industrial complex, the metallurgical industry, information technologies, communications, tourism, electricity and the pharmaceutical industry.

Nigeria has known reserves of 24.1 million barrels of oil and 120 trillion cubic feet of gas reserves. Nigeria routinely holds auctions for licenses to explore and develop hydrocarbon fields. Some 63 oil blocs received such licenses in mid-2005. The process of issuing an oil-prospecting license (OPL) involves three stages -searching for, exploring and developing hydrocarbon fields. Thus, after a company has received an OPL and discovered hydrocarbon reserves, it can begin developing on the field right away.

Russian Federal Energy Agency, at the beginning of November that Russian oil company Zarubezhneft along with its Nigerian partner Stratar Energy Resources Ltd. has received the right to take part in the exploration and development of two prospective gas deposits in Nigeria's Gulf of Guinea. Zarubezhneft has not confirmed nor denied the reports and only said that "work is currently being carried out on prospects for cooperation and possible projects are being agreed upon."

Husky achieves first oil production from White Rose

November 14, 2005. Husky Energy’s first oil production had been achieved from its White Rose oil field on Canada's east coast. Husky, Canada's No. 4 oil producer and refiner, White Rose field off the Newfoundland coast is expected to reach peak production of 100,000 bpd in the first half of 2006. The first shipment of crude oil is scheduled to take place later this month.

Oil output expansion plan on track – Saudi Arabia

November 14, 2005. Top oil exporter Saudi Arabia plans to boost oil production capacity by 1.5 million barrels per day (bpd) by 2009 was on track. The kingdom is proceeding in its current and future plans to raise production capacity as announced, to reach a production capacity of 12.5 million bpd by 2009. This plan is proceeding according to the set schedule and there are no technical or financial obstacles or lack of Saudi human resources.

It is said that a global shortage of equipment could leave Aramco two to three years behind its plan to lift capacity from 11 million bpd now. Riyadh has fast-tracked a $50 billion scheme to keep pace with booming demand and maintain up to two million bpd of oil production in reserve.

LUKoil to up oil and gas production in 2006

November 13, 2005. Russian oil and gas major LUKoil plans to increase its oil production by 5 per cent and gas production two or three times in 2006. The company has settled issues on the West Siberian Nakhodka gas deposit with Russian gas monopoly Gazprom. The growth of the production rate was restrained earlier due to the impossibility of loading gas into Gazprom's system, which was having slight technical difficulties. Gas from the Nakhodka deposit will be loaded into Gazprom's system. LUKoil put the Nakhodka deposit into operation in April 2005. The deposit contains more than 250 billion cu m of gas and some nine million tons of oil.

Deepwater capex to reach $20 bn by ‘10

November 11, 2005.  The deepwater sector is forecast to continue its growth trend and will remain strong over the next five years, reaching an annual total of over $20 bn by 2010. Between now and 2010, expenditure in the deepwater sector is projected to expand at a compound annual growth rate (CAGR) of 7.3 per cent, with particularly strong growth coming from the Asia and Latin America regions.

Exxon wants to boost Africa output by mid ‘10

November 9, 2005. U.S. oil major ExxonMobil aims to boost its African output by 50 percent by the end of the decade as it expands in major producers Nigeria and Angola and steps up exploration in targets like Madagascar. ExxonMobil currently produces about 2 mn oil equivalent barrels per day in Africa on a gross basis. New projects will add around 4 mn barrels a day, but part of this will go to offset declining production at certain operations. ExxonMobil has interests in four blocks in the northeast part of the island that total 22 million acres, a third of the firm's total African acreage. Additional seismic and magnetic surveys are planned for 2006 and anticipate drilling of our first deep water well in 2006 or 2007.

In Angola, ExxonMobil seeks to boost output by 1.3 mn oil equivalent barrels per day by 2010 with eight project start-ups, including an liquefied national gas project. In block 15 - which has combined recoverable resources of 4.5 billion barrels - Kizomba B is now producing 250,000 barrels per day, up from 200,000 when it started production in July. Kizomba C and D are due to come into production in coming years with more than 200,000 barrels and 125,000 barrels respectively. In Nigeria, where ExxonMobil has 15 blocks, around 10 new projects are due to add 1.2 mbpd of production by the end of the decade. The firm has invested $12 bn in Africa since 2000 and plans to spend an additional amount before the end of the decade.

Statoil begins production from Urd field     

November 9, 2005. Oil production started from the Statoil-operated Urd field in the Norne area of the Norwegian Sea on November 8th. With Costs estimated at NOK 3.6 billion, this project helps to secure good capacity utilization on the Norne production ship and in related infrastructure. A total of five oil producers and three water injectors are due to be drilled on Urd, with gas lift planned for the production wells. This means that gas from the Norne ship will be injected in the wells in order to reduce wellstream density and increase production.

These wells are also equipped with technology which can isolate reservoir zones to optimize output, reports Jostein Gaasemyr, operations vice president for Norne. The well stream from the two satellites is carried through a single electrically-heated pipeline to the ship for processing and loading into shuttle tankers with other oil from Norne. Urd also contains small volumes of gas, which will be exported together with Norne output via a tie-in to the Åsgard Transport pipeline and processed at Kårstø north of Stavanger. Recoverable reserves in Urd are put at roughly 70 million barrels of oil and a small amount of gas. Statoil has a 50 per cent interest in the development.


BHP Billiton plans to build gas plant in Algeria  

November 14, 2005. BHP Billiton, which gets almost a fifth of its earnings from oil, had joined Statoil and PetroSA in submitting a proposal to build a gas-to-liquid plant in Algeria, which is seeking to quadruple its output. Australia’s BHP Billiton, PetroSA and Statoil, Norway’s biggest oil company, together made a technical proposal to Algeria’s government for the right to develop the Tinrhert gas fields. The contest pits the three against Sasol, the world’s largest producer of motor fuel from coal. The companies were preparing a commercial bid. The gas-to-liquid project would be a “commercial-scale” plant, not an experimental facility.

Tehran, Jakarta to build oil refinery in Indonesia

November 12, 2005. A subsidiary of the Indonesian state-owned oil and gas company PT Pertamina in cooperation with an Iranian oil enterprise will build an oil refinery in Indonesia. The three billion dollar refinery will have a refining capacity of about 300,000 bpd of crude oil. The refinery would be capable of exporting about 200,000 bpd. The refinery would refine the oil imported from Iran. The agreement to build a refinery in Indonesia with the aim of refining the crude oil imported from Iran was concluded last December in the Iranian city of Isfahan where the oil ministers of the two countries signed the contract. At present, Indonesia’s oil refining capacity stands at 1.06 million bpd.

Dow to build naphtha plant in Thailand

November 9, 2005. Dow Chemical Co. has teamed with Siam Cement PLC, Thailand's largest industrial group, to build a $1.1 bn naphtha-cracking plant in Rayong province on Thailand's eastern coast. Under the signed letter of intent, Siam Cement holds a 67 per cent stake in the scheme, which will be capable of producing 900,000 tonnes/year of ethylene and 800,000 tpy of propylene, using naphtha, condensate, and LPG as raw materials.

Construction of the plant, to be built 220 km southeast of Bangkok, is expected to commence early next year and is scheduled for operation start-up in 2010. In an associated project, Siam Cement alone will invest $400 million in a new downstream facility using olefins derived from the cracker. This plant will be capable of producing 300,000 tpy of high-density polyethylene and 400,000 tpy of polypropylene, also starting in 2010. Siam Cement already operates an existing naphtha-cracking plant in Rayong capable of producing 800,000 tpy of ethylene and 400,000 tpy of propylene.

Transportation / Distribution / Trade

ExxonMobil and Qatar Petroleum progress LNG project     

November 15, 2005. Qatar Petroleum and ExxonMobil Ras Laffan (III) Limited, a wholly owned subsidiary of Exxon Mobil Corporation launched Ras Laffan LNG Company Limited (RL3). RL3 is a further expansion of the existing LNG production facilities operated by RasGas Company Limited (Qatar Petroleum 70 per cent; ExxonMobil 30 per cent) at Ras Laffan Industrial city in North Eastern Qatar. This project is planned to bring the total number of trains operated by RasGas to seven (Trains 1 and 2 in RL, 3 through 5 in RL II and 6 and 7 in RL 3) and is expected to increase RasGas LNG production capacity by more than 70 per cent.

Full-chain investment in RL 3 is estimated at near $14 b. This includes the design, construction and operation of two 7.8 million-ton-per-year (MTA) LNG Trains 6 and 7, and all other facilities associated with the development, production, transportation, processing, treatment, liquefaction, regasification, storage, delivery and sales of approximately 15.6 million tons a year (MTA) of LNG along with associated by-products such as liquified petroleum gas, condensates, helium and sulphur.

The new LNG project, one of the largest ever announced, will be developed in two consecutive phases with Train 6 scheduled to begin production in the second half of 2008, and Train 7 anticipated to come on stream approximately one year later. Twenty-eight wells are planned to be drilled to supply the two trains with natural gas, sourced from Qatar's giant North Field, which is estimated to contain natural gas resources in excess of 900 trillion cubic feet. LNG from the project will be delivered to targeted markets, principally the United States. To deliver the LNG to its targeted markets, RL3 plans to lease 12 LNG tankers to support Train 6 to be constructed by Hyundai Heavy Industries, Daewoo Shipbuilding & Marine Engineering and Samsung Heavy Industries. Daewoo will build five tankers, Samsung four and Hyundai three. It is expected that an additional six LNG tankers will be required to support Train 7.

Saudi crude imports to be increased

November 15, 2005. China aims to boost Saudi crude imports by 14 per cent next year, ensuring a hefty share of term deals as it strives to limit the impact of its spot buying on volatile prices. Top lifter Sinopec is slated to conclude talks with state-owned Saudi Aramco soon as part of its plan to keep long-term supply at nearly 70 per cent of its total crude import requirement versus 55-60 per cent a few years back. If agreed, imports from the world's top exporter next year would hit a record 500,000 barrels per day (bpd), up from 440,000 bpd this year, keeping the kingdom at the top of China's list.

The world's number two oil consumer is also set to buy more crude from other Middle Eastern nations, Africa, Russia and Venezuela via long-term contracts, hoping to downplay its role in oil markets spooked by a 34 per cent surge in imports last year. Higher imports may mean Saudi Arabia, which accounts for nearly a third of output from Opec, will cut back supplies to other customers or pump more crude than this year's 9.5 million bpd. Major producers such as Saudi Arabia, Iran and Venezuela are keen to strengthen bonds with fast-growing Asian consumers China and India. The move is partly a way to offset a dependence on the huge US market, which consumes nearly one in four barrels worldwide. For China, boosting supplies from Saudi Arabia will soothe its own growing insecurity over rising energy imports and may help offset a perception of Chinese firms as insatiable buyers, gobbling up crude and driving up prices. The International Energy Agency expects oil demand growth to accelerate to 6.5 per cent in 2006.

Kazakhstan-China oil pipeline completed

November 15, 2005. China National Petroleum Corp. and Kazakhstan's National Petroleum & Natural Gas Co. have completed construction of the 1,000-km Atasu-Alashankou oil pipeline. The new line, which extends from Atasu in Kazakhstan's central Karaganda region through the Alashankou rail crossing with China's western province of Xinjiang, is designed to carry 140 million bbl/year of crude from Kazakhstan to China starting Jan. 1, 2006. Russian state-owned oil company Rosneft, which currently transports oil to China by rail, has applied for permission to transport 1.2 million tonnes of oil via the Kazakhstan-China pipeline in 2006. OAO Lukoil also is said to have shown interest in the pipeline.

Gazprom stalls on Turkmen gas

November 14, 2005. Gazprom has curbed plans to export Central Asian gas to Europe after Turkmenistan, the largest producer in the region, delayed confirmation of its reserves. Gazprom agreed that KazMunaiGaz, the Kazakh state oil and gas company, would ship as much as 55 billion cubic meters of gas per year in 2006-10 from Central Asia to Russia. Moscow-based Gazprom had planned to buy as much as 80 bcm of gas per year from Turkmenistan starting in 2008.

Gaz, Kazakh reach gas transit agreement

November 11, 2005. Russian natural gas giant Gazprom and Kazakhstan's biggest natural gas company, KazMunaiGas, have signed an agreement on the transit of Central Asian gas through Russian territory. Uzakbai Karabalin, the president of KazMunaiGas, said: The agreement is for five years and allows the transit of Uzbek and Turkmen natural gas via Kazakhstan to be increased to 55 bcm from the current 47 bn.

Indonesia to sign LNG contract with Japan     

November 10, 2005. The Indonesian government will sign an agreement on the extension of a LNG supply contract with Japanese buyers at the end of this month. Ehe existing LNG supply contract of 6 million metric tons per annum will expire in 2010. The chairman of the Upstream Oil and Gas Regulatory Agency, or BP Migas, as saying both sides have agreed on the pricing formula for LNG cargoes produced by an LNG plant in the town of Bontang in East Kalimantan Province. The prices will be based on the average Japanese crude oil import price, known as the Japanese crude cocktail. The Japanese buyers are also interested in extending the contract of another 6 million tons a year from Bontang. But no decision has been made over the request.

El Paso to expand gas pipeline project in Utah

November 9, 2005. El Paso Corp. will add 128 miles of natural gas pipeline to expand its Uinta Basin project in eastern Utah. Kerr-McGee Corp. has agreed to contract for firm transportation capacity on the pipeline. The 20- or 24-inch pipeline will link processing facilities near a Colorado Interstate Gas plant with the Overthrust Pipeline and Wyoming Interstate Co. in Sweetwater County, Wyoming. The new line will add capacity of between 250,000 to 350,000 dekatherms of gas per day.

Gassco plans to build $1.3 bn pipeline to Sweden     

November 9, 2005. Norway's natural gas infrastructure operator Gassco outlined preliminary plans to build an 8.64 billion Norwegian kroner ($1.3 bn) pipeline to eastern Norway and Sweden. The pipeline - if approved by investors and Gassco - would create a domestic natural gas market for Norway and more than triple Sweden's gas imports. Fifteen companies interested in the project are expected to sign a letter of intent next month giving Gassco the go-ahead to prepare more detailed plans.

Power companies and energy-intensive industries say a domestic market in Norway will preserve the country's processing industries and new piped gas imports into Sweden would allow industry expansion and more competitive energy prices. Gassco's preliminary plans are for a pipeline from the Kaarstoe gas processing plant in Western Norway, running offshore around the southern coast of Norway, then landing onshore and feeding into the Telemark industrial complex. It would then split into sections feeding into Oslo and Sweden.

Initial startup is seen around 2008, providing around 3 bcm a year, increasing to around 7 bcm/yr by 2015. The Norwegian side of the pipe would cost roughly NOK6 billion, with the Sweden leg another NOK2.5 billion. According to Lohne's presentation, demand from the Telemark complex would be between 5.5 million cubic meters a day to 7.5 mcm/d, 5 mcm/d to 10 mcm/d from Sweden and 1 mcm/d to 3 mcm/d from Oslo.

Policy / Performance

Russia, Ukraine approve pipeline feasibility study

November 15, 2005. Russia and Ukraine have approved a feasibility study on the Bogorodchany-Uzhgorod pipeline project, which will increase the capacity of Ukraine's natural gas transportation system in the direction of Western Europe. The construction of the pipeline is being planned within the framework of the International Consortium for Managing and Developing the Gas Transportation System of Ukraine, which was established in 2002 under a Russian-Ukrainian agreement on strategic cooperation in the natural gas sector. 

The parties agreed on a three-stage implementation of the project. Construction of the main 50-km segment of the pipeline, which will cost $130 million, is due to start this year and will be operational in 2006. The estimated annual capacity of the Bogorodchany-Uzhgorod pipeline is 19 billion cum and the project's total cost is estimated at $560 million. The pipeline will run 234.3 kilometers (145 miles) in western Ukraine.

European Comm.  against energy imports from Russia

November 15, 2005. The European Commission will not import energy from Russia until security in the country's nuclear power sphere is heightened. Russia should firstly shut down dangerous reactors. Russia's share in European energy imports was 2% and was unlikely to increase by 2020 and Russia's share in European oil imports was almost 33%, and in natural gas imports, about 50%. Unlike the EU, Finland is more dependent on Russian energy, which constitutes 14% of all power consumed in Finland.

Indonesia may cut Belanak oil export a third in '06

November 14, 2005. Indonesia's BPMIGAS may reduce its monthly exports of Belanak crude oil by a third to 400,000 barrels next year to feed the domestic market due to persistently high oil prices. BPMIGAS, the country's oil and gas regulator, plans to issue a semi-term tender in December, to sell the light sweet crude with loading to start from January. The term period could be for three to six months. BPMIGAS may cut the export volumes.

Indonesian refineries could blend the Belanak crude with other grades to dilute the mercury content. The daily output of Belanak, which came onstream late last year, was pegged at 30,000 barrels. There is nothing wrong with the oilfield but Indonesia wants to keep supplies for domestic consumption. BPMIGAS supplies 600,000 barrels of Belanak crude under an existing term contract to a European trader between September and December. The price was at a discount of $1.50-$1.70 a barrel to the Minas Indonesia Crude price (ICP).

Indonesia's crude oil production sank to a 34-year low of 927,500 barrels per day (bpd) in September, falling short of its output target, though the daily output in October inched up to 939,000 barrels. OPEC's only Asia-Pacific member was a net importer of crude throughout the second quarter of this year, as its ageing oilfields decline at a 5 percent rate or more a year. Indonesia has nine refineries spread across the archipelago with a total capacity of 1 million bpd. The refineries of state oil firm Pertamina supply about 75 percent of domestic oil product consumption, while the rest are imported directly.

Inpex plans to raise Sakhalin-1 stake

November 12, 2005. Inpex Corp, Japan's top oil developer, is considering lifting its stake in Russia's Sakhalin-1 oil and gas project as part of its effort to increase muscle in the global fight for energy resources. Inpex, which is 36 per cent state-owned, said it may raise its stake in the massive oil and gas project to 10 per cent from the current 1 per cent by buying additional shares in Jap-anese consortium Sodeco from the Japanese government. Sodeco, half-owned by the Japanese government and half by private firms, has a 30 per cent stake in the Sakhalin-1 project. Inpex is considering upping its stake in Sodeco to 33 per cent from 4 per cent, giving it 10 per cent of the overall project.

The Sakhalin-1 project is one of the largest single foreign investments ever made in Russia, and about $12.8 billion is expected to be committed to developing the three fields over a lifetime spanning about 40 years. US oil major ExxonMobil Corp is the operator of the project and holds a 30 per cent stake. India's state-run Oil and Natural Gas Corp. Ltd owns 20 per cent. The Sakhalin-1 oil and gas field started pumping oil off Russia's Pacific Coast from October 1. Initial production from Sakhalin-1, which will rise to about 50,000 barrels a day by year-end, is currently sold on the Russian domestic market.

Output from the Chayvo field is expected to rise to full capacity of 250,000 barrels per day by the end of 2006 when a pipeline linking the island to an export terminal in the Russian mainland sea port of Dekastri will also allow shipments to international markets, including Japan. Exports would start from the middle of next year (2006). The crude supply from Sakhalin-1 would help Japan to diversify its crude imports.

The world's third biggest oil consumer relies on the Middle East for most of its crude oil needs. Sakhalin lies off Russia's Pacific coast and is just north of Japan, which occupied half of the island from 1905-1945. Gas production from the field starting at about 1.7 million cubic metres a day and later rising to 7.1 million, will also at first be sold only to Russian consumers in the mainland Khabarovsk region bordering China. Sodeco, working in partnership with the Soviet government, discovered oil off Sakhalin in the 1970s, but an agreement to develop the resources was not concluded until the mid-1990s, when Exxon joined the venture.

Asia fuel oil falls below $300/T

November 11, 2005. Singapore benchmark 180-cst fuel oil prices fell below $300 a tonne for the first time in three months, but premiums remained firm on expected tight supplies until the year end. Prices for the benchmark 180-cst grade closed at $295.20 a tonne, down $6.70 from Asian close as benchmark crude futures slumped to $57 a barrel, while the 380-cst grade was lower by $7.60 at $281.70.

Premiums for both grades were marginally lower, with the 180-cst premium at $3.75 a tonne, down 25 cents, while the 380-cst premium was 50 cents lower at $3.75. However, the product's physical crack to Middle East Dubai crude resisted the fall and was stable at a discount of $6.57 a barrel, down 1 cent.  About 1.6 million tonnes of Western cargoes are expected to land in East Asia in December, with 1.4 million tonnes having been already fixed.

The total is steady to November but below the monthly average of 1.7 million tonnes. In the face of anticipated firm demand from both the Asian marine fuels market and the Chinese utility market this could fall short of market needs. Reflecting the bullish sentiment, Saudi Aramco has set higher minimum differentials for term 380-cst cargoes from its Jubail refinery during its ongoing annual term talks for the first half of 2006. The oil giant has set a minimum discount of $8-$9 a tonne to Singapore 380-cst quotes on a free-on-board (FOB) basis for cargoes to be delivered to Singapore, compared to $10 in the first two quarters of 2005. However, the low-sulphur market appears to be weakening as a November-allocation parcel was seen making its way to China, indicating that demand from traditional sources like Japan and South Korea has slumped. Demand from Japan, the largest consumer of Indonesian LSWR, has slowed in the face of a warmer winter and having two nuclear units back online.

Turkey plans $10 bn energy plants at Ceyhan

November 11, 2005. Turkey plans a $10 bn project to build an oil refinery, an LNG terminal and a petrochemicals plant at the port of Ceyhan on its Mediterranean coast. Turkey wants to promote Ceyhan as a hub for regional oil and gas trade, partly as a way to avoid crowding in the narrow, congested Bosphorus straits and the passage through Istanbul, the only outlet for Russian and Caspian oil output.

Ceyhan is already the terminus of 1.5 mbpd pipeline and a terminal for Iraqi crude. Another line with a one million bpd capacity from Baku on the Caspian through Tbilisi will come on stream in early 2006. The terms of the project will be announced by the end of the year. The government has started talks with leading international energy companies to build the project. A total investment value of $10 bn has been calculated for the three plants. A total of nearly 200 million tonnes of oil a year (four million bpd) will converge at Ceyhan from Iraq, Caspian as well as Russia through the proposed Samsun-Ceyhan line, the Samsun-Ceyhan line might carry 1.4 million bpd.

Lukoil wants to expand cooperation with PDVSA     

November 11, 2005. Russian oil companies are interested in expanding their work in Venezuela. Lukoil wants to expand its work with the Venezuelan state oil company PDVSA in terms of participating in projects to determine and certify geological reserves of hydrocarbons in various areas of the Orinoco River basin. Lukoil Overseas, Lukoil's international production projects subsidiary, has already signed a deal with CVP, the PDVSA investment subdivision, on studying the Junin-3 block.

Zarubezhneft is interested in working with PDVSA and taking part in the exploration and development of the Caribas field. It is also interested in working with Suelopetrol C.A., S.A.C.A. and other companies. Zarubezhneft, a Gazprom subsidiary, has already won auctions for two out of six blocks in the Rafael Urdaneta gas project. Russian oil companies are interested in Venezuela because it has proven oil reserves of over 10 billion tonnes and it is a main supplier to the United States. Venezuela wants to distance itself somewhat from the United States and diversify its foreign economic relations.

UAE urges oil producers to cooperate

November 11, 2005. The UAE has urged co-operation among all oil producers to support sagging crude prices, and the call was promptly backed by non-OPEC Oman. There is a need for all oil producers, whether they are OPEC members or non-OPEC members, to control any surplus output especially in the current global economic circumstances. Co-operation among oil producers and ‘understanding’ by consumers would benefit the world’s economy in the long term as it would create balance in the oil market and ensure supplies to the consumers.

Ondo signs MoU on $1.5 bn private refinery

November 10, 2005. WORK would soon begin on the US $1.5 bn private oil refinery to be sited at Ode-Aye in Okitipupa Council area of the state following the arrival of the foreign patners to the state. The MoU of the refinery was signed between the state government and the foreign partners last year. Vanguard gathered that the foundation laying of the refinery would take place tentatively in March next year while production would commence before the year 2008. The people of the state are eager for the take off of the project, which would boost tremendously the economy of the state.

Russia to bring in new reserve rules from 2009

November 10, 2005. Russia will adopt new rules for classifying oil and gas reserves from 2009 to bring the system in line with international standards. Russia's government is considering giving oil producers tax breaks for developing remote and complex deposits, and could use the new system as a basis for taxing such fields. The new system will not replace audits of oil reserves for Western classification standards. The current system is based on government surveys and ignores factors such as whether oil can be economically brought to market crucial for evaluating Siberian fields, which may be rich but thousands of miles from any transport link.

The new system includes a more clear-cut definition of reserves and resources, a reduction of reserves categories and the classification of reserves according to how efficiently they can be developed. The new classification will use DCF (discounted cashflow) and probability analysis in reserve estimates, thereby making valuations more understandable to foreign investors. Reserves estimates will be made at a probability of 10 per cent, 50 per cent and 90 per cent. Private Russian majors, such as Lukoil the world's second largest private holder of oil reserves after US ExxonMobil have long reported their reserves to international standards.

Russia sees Arctic oil cooperation with Norway

November 10, 2005. Russia predicted closer cooperation with Norway in developing Arctic oil and gas as part of a drive to promote ties across the northern tip of Europe after the Cold War. Russia and Norway, the world's number two and three oil exporters respectively behind Saudi Arabia, are both looking north for new finds. By some U.S. estimates, the Arctic could hold a quarter of the world's undiscovered petroleum reserves. Cooperation could include both production of oil and gas and specialised equipment for work in the Barents Sea region, where costs are high because of factors including freezing cold, winter darkness and the risk of icebergs. Norway wished for closer ties on oil and gas. But Norway hoped for common international standards for oil and gas exploitation in the Arctic to protect the fragile environment.

Statoil to pump 100-200kbpd in Russia by ‘20

November 9, 2005. Statoil is aiming to pump 100,000-200,000 barrels of Russian oil per day by 2020 in partnership with local firms. Statoil had good relations with state oil company Rosneft and gas monopoly Gazprom. Statoil is short-listed with four other foreign companies to help Gazprom extract gas from the vast Shtokman field a mile below the Arctic Barents Sea.

It is also a partner in major Caspian projects, the offshore fields Azeri-Chirag-Guneshli and the Baku-Ceyhan pipeline which will carry their oil around the Turkish Straits to the Mediterranean. Statoil was tempted by regions ranging from the oil provinces of Western Siberia, where fields are more mature, to Sakhalin in Russia's Far East, where oil and liquid natural gas projects are under development to supply Asian markets.

LUKoil to set up special company to produce, sell oil

November 9, 2005. Russian oil major LUKoil has decided to establish a 100 per cent subsidiary, LLC International, to produce and sell oil. The new subsidiary will consolidate the company's accounting, objectively assess financial results, promptly respond to the market situation, improve and develop the production of oil, conduct research, and optimize oil sales with minimal infrastructure changes. The new subsidiary will conclude the company's management reforms in this segment that began in February 2005.

The decision to establish a new subsidiary was based on the experience of strategic partnership between LUKoil and ConocoPhillips. Leading international oil companies, which have separated this business, have been able to achieve positive results and maximum transparency. LUKoil refineries produce more than 40 per cent of oil in Russia. In the first half of 2005, LUKoil's production reached 550,800 metric tons.



AGL steps on gas with $200m plan

November 16, 2005. AGL is planning NSW's biggest gas-fired power station, providing a market for the PNG gas project. Australia's biggest energy distributor, which is moving to split its energy business from networks operations, it would spend $200 million on a gas-fired plant at Campbelltown in Sydney's southwest. AGL was also looking to expand the Campbelltown site in stages with up to 500 MW of gas-fired power generation. The 300MW first stage could be operating by 2009, when first gas from the proposed $US3.6 bn ($4.9 bn) PNG gas project is expected. AGL, which could spend up to $93.3 million to buy half of Sydney Gas's coal-seam gas project at nearby Camden, said demand made it clear that coal-seam gas supplies would not be sufficient to fuel its new gas plant.

Transmission / Distribution / Trade

GEECF targets US $1 bn coal market in Spain and Morocco

November 9, 2005. Global Environmental Energy Corp. and the Algerian company, Geoinvest Ltd., have entered into a MOU and articles of confidentiality with the Shenzhen Branch of Yankuang Group Co. Ltd., and Shenzhen Environmental Energy Technology Co., Ltd., to develop a coal mine in Algeria. Preliminary data from Geoinvest Ltd., indicate that the coal deposit may be in excess of one billion tonnes with a present market value of @ US $50 per tonne. The deposit is @ 10 kilometers from a railroad and @ 150 kilometers from the port of Oran. Global and ETT intend to have Yankuang manage the mining and marketing operation on this property, selling the extracted coal in both Spain and Morocco which currently import in excess of 20 million tonnes of coal per annum from Columbia, the United States and South Africa, incurring ever increasing ocean transport costs. By contrast, Oran is less than 300 kilometers from both clients.

Honeywell signs contract for thermal power plant in Bulgaria

November 9, 2005.  Honeywell a diversified technology provider and manufacturer has entered into a contract valued at US$11mn, with a thermal power plant in Bulgaria. Under the contract, Honeywell will supply its Experion Process Knowledge System (PKS), field instrumentation, basic design, engineering and installation services for the Maritza thermal power plant, which is located near Stara Zagora in Bulgaria. The Maritza plant will use Honeywell's technology to modernise itself and use process data more effectively for future planning and cost management. The project is planned to be completed in three phases, with commissioning and start-up of all units to be completed by 2008.

Policy / Performance

Tullow sees opportunities in African power

November 14, 2005. Tullow Oil, which is commercialising the Kudu gas field off Namibia, is confident a $1.1 billion (R7.4 billion) project to build a gas-powered station near Oranjemund will give it "first-mover advantage" in the region's gas market. FTSE-listed Tullow acquired Kudu when it bought Energy Africa for $570 million last year. This would open opportunities for the Irish-based company for future phases of the Kudu project. In the meantime, Tullow had opted to separate the first phase of the project from future opportunities. Phase one involves treating and delivering gas from the Kudu field to an onshore station operated by Namibia Power (NamPower).

The rationale for isolating the first phase is to take commercial advantage of Kudu's proven reserves of 1.3 trillion cubic feet. The power station is expected to be commissioned by 2009 with initial electricity output of 800 MW, half of which will serve the Namibian market. The remainder will be exported to South Africa. Eskom has plans to spend R83 billion in the next five years on new generation and transmission capacity. Tullow recognised there was a "window of opportunity" in the region's power market, where about 40 000 MW of capacity was installed and demand was growing by about 1 000 MW a year.

Coking coal prices may fall 28 per cent: JP Morgan 

November 11, 2005. Prices of coking coal, used to make steel, may fall 28 per cent during the next two years as new mines start production.  Coking coal prices may fall to $90 a metric tonne in 2007 from a record $125 this year. Australia, the world’s no.1 coking coal producer, will increase exports by 8.7 per cent in 2006, according to the government.

BHP Billiton, Xstrata Plc and other miners are raising production to take advantage of coking coal prices that have more than doubled since the 1990s, driven by demand from Chinese steelmakers. That extra production may make coking coal cheaper as growth in Chinese steel output slows. Coking coal prices are negotiated annually by miners and steelmakers. Prices for 2006, under discussion, may fall 4 per cent to $120 dollars a tonne.

Australia’s extra supply will come from new mines including Moranbah in Queensland, slated to produce 1.5 million tonnes of coking coal next year. Existing mines, including Rio Tinto Group’s Hail Creek, will also increase production capacity. Growth in China’s steel production may slow to 15 per cent next year from 20 per cent this year. Production may rise to 390 million tonnes next year from a forecast 340 million this year. The government plans to cap output at 450 million tonnes a year in the next five years to prevent overexpansion in the industry. Coking coal is heated in ovens to make coke, pure carbon used in blast furnaces. Steelmakers use about 0.63 tonnes of coke for each tonne of alloy they produce.

UBS raises uranium price estimates 

November 11, 2005. Uranium prices during the next three years may be higher than forecast as the rising cost of crude oil and natural gas and increased environmental concern prompt countries to switch to nuclear power generation. Uranium prices may average $38 a pound in 2006, 41 per cent higher than earlier estimated. The price of uranium ore, used to fuel nuclear plants, has surged 62 per cent this year to $33.25 a pound on Nov 9.

Iran offered nuke-power deal

November 10, 2005. The European Union and the US have offered Iran a compromise over its nuclear programme. The deal means Tehran can convert raw uranium into a low-level gas that can be enriched to generate electricity in nuclear power stations. EU has approved a plan that would allow Iran to continue raw uranium conversion, but the actual process of enrichment would take place in Russia. If Tehran accepts the deal to send uranium to Russia to be further enriched, it would still be able to use the enriched uranium for fuel purposes, but the threat of building atomic weapons would be reduced. Iran concealed its uranium enrichment programme from the IAEA for 18 years, fuelling fears in the west that it was developing an atomic bomb. Tehran has always denied that it is enriching uranium to be used as atomic weapons and says it needs nuclear power to fuel its expanding demand for electricity.

Earlier this week, Iran said it had allowed inspectors from the nuclear watchdog, the International Atomic Energy Agency (IAEA), to tour its facility in Parchin, 20 miles south of Tehran. The US had claimed that Parchin was used to develop explosives that could be used in nuclear weapons. Raw uranium can be converted into hexafluoride gas, which can then be spun by centrifuges into enriched uranium. Enriched uranium is used in nuclear power plants, or can be further enriched to weapons-grade material.

Britain buys into next generation of nuclear power

November 10, 2005. Britain is investing millions of pounds in a US government project to develop a new generation of nuclear power stations. The move restarts UK government funding for research into new nuclear reactor technology and gives its scientists access to international efforts to develop a "generation IV" nuclear power station by 2030. The investment is not directly connected to the coming decision on whether to build new nuclear power stations in Britain, which would use existing reactor designs, but is significant because it shows the government has not ruled out nuclear energy as a long term solution.

Britain joined the US Department of Energy's generation IV forum in 2000, alongside eight countries, including France, Brazil and Japan. It supported the project through BNFL but did not commit state funds directly. The generation IV scheme has shortlisted six possible designs, which it claims will be cheaper, cleaner and safer than current reactors. The move comes as a report turns up the heat on the nuclear debate by reiterating that new reactors are almost certainly needed if Britain is to meet future energy demands without busting greenhouse gas targets.

Based on a meeting of 150 scientists, engineers, economists and sociologists at the Geological Society, the report says nuclear power "will inevitably have a key role in a future clean energy mix". Without new nuclear build, it says, Britain will struggle to plug an anticipated 10,000 MW energy gap - some 20 per cent of demand - which is expected to open by 2015 as existing power stations are retired.

Renewable Energy Trends


Vestas to make wind power generators

November 15, 2005. Vestas RRB India will invest Rs 100 crore ($22 mn) to make wind electric generator blades at first, and then wind electric generators in Sriperumbudur. The factory is expected to start production in six months. In the first phase of the project, Vestas will invest Rs 35 crore ($7.7 mn) to make the blades. Vestas India provides the whole range of services in the area of harnessing wind energy for power generation. A domestic manufacturing site for blades is expected to help the company reduce the installation cost as well as the lead time for the procurement. The company estimated that domestic manufacture of blades would bring down its cost by 10-15 per cent, as compared to the price paid today to import the same. The lead time to get the blades is expected to come down to 40 days from the current level of 120 days. 

AP plans $1 bn bio-diesel plantation project

November 14, 2005. The State Government has decided to facilitate large-scale cultivation of bio-diesel plants such as jatropa and pongamia in over 50 lakh acres at an investment of around Rs 5,000 crore ($1.1 bn) over the next three years. The move is aimed at ensuring a sustainable income for farmers in the arid areas and to effectively implement the rural employment guarantee programme. The Government proposes to contribute around 60 per cent of the cost, about Rs 2,800 crore ($615 mn), while banks will extend lending support for the balance ($483 mn). The Government has also decided to coordinate bio-diesel plantation in 22 districts of the State, of which 13 districts are covered under the National Rural Employment Guarantee Scheme. The State Government has also decided to offer a minimum support price of Rs 6 per kilogram of bio-diesel seeds and proposes to earmark a Rs 5-crore ($1.1 mn) fund towards this in the next budget.

The Girijan Corporation and the women self-help groups (SHGs) under the Indira Kranthi scheme in the State will be permitted to procure bio-diesel seeds from the farmers and the State-owned AP State Road Transport Corporation would buy the entire bio-diesel production. For extracting bio-diesel from the seeds procured across the State, the Government proposes to encourage women SHGs to set up expelling units with a capacity of 220,000 tonnes per annum, involving an investment of around Rs 400,000. The Government also plans to invite expressions of interest from corporate houses and non-governmental organisations towards setting up bio-diesel extraction units.

Need of 3 P’s to rise oilseed production: Agri Ministry

November 13, 2005. To meet the growing demand of edible oil in the country, private-private partnership is required to enhance production of oilseeds. There was a need to increase the oilseeds production from the present 6 mt. The government alone would not be able to address the issue of increasing the production and the industries must select at least 100 districts in the start to initiate the process of private-private partnership. The role of farmers is very important in this regard. There is greater need for developing "symbiotic relationship" between farmers and industry for the enhancement of production of oilseeds.

New buildings must tap solar energy: Oscar 

November 11, 2005. Minister for statistics and programme implementation Oscar Fernandes said tapping the vast potential of solar energy should be made mandatory for all new buildings and complexes. This would help save power and meet the growing energy shortage. Underlining the importance of solar energy, he said that even countries who hardly get 25 per cent of sunlight tap it to meet their energy requirements.

India accedes to new Kyoto convention

November 11, 2005. With India becoming the 40th country to accede to the Protocol of Amendment for the Revised Kyoto Convention, the convention is set to become effective from the first week of February 2006. According to the terms of the protocol, the revised convention could come into force when at least 40 of the contracting parties to the convention of 1973 acceded to the protocol.

India awarded for harnessing wind energy 

November 8, 2005. India has been honoured with the World Wind Energy Award-2005, by virtue of being ranked fourth in wind energy generation capacity. The award was in appreciation for favourable government policies for encouraging wind energy generation. Power generation from windmills in India, the world's fourth largest producer of wind energy, has increased fourfold in the past three years. The country produces 4,228 MW of power from windmills, including 632 MW added in April-September, the first half of the fiscal year. In addition, the ministry of non-conventional energy sources has prepared master plans for 97 potential sites aggregating to 15,062 MW wind power potential.


Panda & Lurgi sign ethanol plant construction agreement

November 15, 2005. Panda Energy and Lurgi PSI had reached an agreement for Lurgi to build Panda's 100 million gallon fuel ethanol plant in Hereford, Texas. Construction on the $120 million facility should begin in December 2005 and be completed by December 2006.  Once in operation the plant will be the largest biomass powered fuel ethanol refinery in the United States. The facility will convert one billion pounds of cattle manure into a clean burning bio-gas that will be used to power the plant's operation.  By using bio-gas instead of natural gas the facility will save the equivalent of 1,000 barrels of oil per day, which will make it the most efficient refinery in the United States.

Panda's Hereford ethanol plant will help reduce imports of foreign oil, protect the environment and save natural resources.  The United States imports about 60% of the crude oil it refines.  The Hereford plant will replace 2.4 million barrels of imported gasoline each year.  Since 1978 every automobile produced for use in the United States can run on a 10% fuel ethanol blended gasoline, (E10), which reduces harmful carbon monoxide emissions by 25%.  Automotive manufacturers are now producing cars and trucks that use a blend of 85% ethanol with gasoline (E85).  When using E85, harmful emissions of carbon monoxide are reduced by 40%.

Wind energy to power Dubai

November 11, 2005. Wind energy may soon be powering homes in Dubai if a pilot project is successful. Dubai Water and Electricity Authority (DEWA) have appointed a consultant to study the feasibility of using wind energy in Dubai. Wind speeds in the UAE often exceed the minimum of seven metres per second required to harness power, often reaching up to 12 metres per second. Implementation of other renewable energy sources like solar power is hampered by many factors. Currently, DEWA and oil companies limit the use of solar power to monitoring water flow or combating rust in pipes. The Department of Renewable Energy predicts up to half the UAE's required energy will come from renewables by 2050.

TexCom plans to second Gulf Coast biodiesel plant

November 10, 2005. TexCom, Inc. has signed a lease agreement with Puerto Los Caballeros Properties, LP for a site in Corpus Christi, Texas on which TexCom plans to build and operate a new 30 million gallon per year biodiesel plant. TexCom plans to construct the second biodiesel process unit at the 11.6 acre Corpus Christi location, utilizing on-site storage capacity and other terminal facilities to be provided by Puerto Los Caballeros under a long-term lease. PLC estimates it will invest in the range of $6 to 9 million for construction of new facilities at the site, including tankage, transport loading racks, utility connections and other infrastructure. The facility will include the capability to store conventional petroleum diesel, allowing TexCom to blend and market B20 and other biodiesel blends as well as B100.

Feedstock for the plant will be virgin soybean oil that will be brought in via barge or rail to the site, located on the Corpus Christi Ship Channel. The company intends to negotiate a lump sum, turnkey Engineering, Procurement and Construction Contract for design and construction of the biodiesel plant. In connection with the project, TexCom is negotiating with Top Water Management, LLC (an affiliate of PLC) to enter into a marketing agreement for sales and distribution of B100 and B20 produced at the new Corpus Christi facility. TexCom is in the process of securing funding for the biodiesel process unit with a goal of getting construction underway by the end of this year. Plans are to have the plant fully operational and producing biodiesel by the end of 2006.



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