Energy News Monitor I Volume I, Issue 16

Value Creation in the Upstream Petroleum Industry

“We go from one imaginary reality (rocks at 9000 feet) to another (oil price 10 years from now).  This is why we all love the oil business: ‘invisible risks’ in time and space, which need multi disciplinary organisations and advanced technology to quantify a decision…” Haldorsen 1996.

 

The petroleum industry is one of the largest industries in the world.  It is international -  oil is produced in over 75 countries; it involves high technology -  some of the oil platforms of the North Sea are counted among the wonders of the world; it is high reward - gross margins of over 60 per cent before government take is common among players.   Within the oil & gas sector, upstream operations offer a number of challenges to an analyst.  The diversity of functions within the upstream industry and the range of professional and management skills necessary to accomplish them make it difficult to categorise it under traditional manufacturing industries.  Attributes of ‘competition’ and ‘co-operation’ coexist among the same actors in different phases of an upstream project posing a challenge when the industry is looked at through a single theoretical lens. 

Internal and external forces make change & adaptation a necessity in the oil industry. The period of high oil prices in the 1970s and early 1980s stimulated much oil exploration activity and provided scope for ambitious projects all around the globe; bringing oil projects on stream quickly was often more important than costs of the recovery methods.  The oil price collapse of 1986, forced the challenge of exploring for and producing oil against a background of continuing low oil prices.  The industry adapted with innovative technical solutions that have enabled to reduce costs even in extreme cases of exploring the deep offshore in frontier areas and redeveloping existing fields in mature provinces.  The current environment has brought to the fore multiple threats of terrorism, corruption and political tension in producing countries.  The imminent peak of oil production is another serious threat. 

Actors in the upstream oil sector thus face uncertain outcomes at a broader level which is reflected in the current debate on the proposal to merge upstream and downstream oil companies in India.  While it is futile to predict the broader future for the oil & gas industry it may be appropriate to look at firm level activity where outcomes are more certain to understand the logic of value creation within the industry. 

 

Value Creation

 

In petroleum exploration and production value created seldom correlates with finding costs: finding a very large field costs approximately the same as finding a small field thus it is imperative to look beyond cost to create value in this sector.  The value creating activities carried out in the upstream oil industry are:

·          acquiring the right to find hydrocarbon deposits in a specified area (obtaining a licence for a specific acreage)

·          ‘finding’ hydrocarbons (exploration)

·          developing the assets found (development)

·          bringing subsurface hydrocarbon resources to the surface (crude production)

Acquiring Acreage/Licence

 

In order to explore for, find, develop and produce hydrocarbon assets, an upstream company has to first acquire the right to explore for hydrocarbons in a specified acreage.

 

·       Acreage can be obtained from the holder of existing acreage; that is, acreage that has already been allocated to an oil company by the Government which holds the title to subsurface resources.

·       It can be new acreage obtained from the government or its agent.  The term ‘new’ does not mean that it is unexplored.  It may be virgin territory, but it is likely that new acreage has been unsuccessfully explored before, has reverted thereafter to the government, and is now available for reissue.  

 

Acquisition methods of ‘farm-in’ and ‘earn-in’ can be used when an existing holder is seeking to dispose off a part of its interest in the acreage.  A sale/purchase or a swap of a partial interest is also possible, but sale/purchases and swaps are only methods an existing holder can use when seeking to dispose of his interest.  In the case of new acreage, Governments can allocate acreage using discretionary or non-discretionary methods.  In the former case, authorities decide which applicant shall receive the acreage; in the latter case, acreage is awarded according to some objective criterion, usually the highest bid, free from governmental influence.  Obtaining existing acreage through earn-in is similar.  Just as there is a farm-in and farm out, there is also an earn-in and earn-out.  The difference between farm-in and earn-in is of timing.  When a buyer farms in, he immediately becomes a party of the group, and later fulfils the obligation he agreed to carryout.  By-contrast, with an earn-in, the buyer does the work and then joins the group.  If the buyer fails to perform, he does not join.  Even though earn-ins appear cleaner for partners, it is much rarer because of complications in tax deductions and governmental approval.  The sale and swaps route is a ‘win-win’ solution to both parties.  If a firm finds in its portfolio, acreage that it does not value any more relinquishing it to the government, swapping or selling provides a way out. The government can issue acreage either by making discretionary or non-discretionary awards.  In a non-discretionary award the bids are opened publicly, and the highest bidder gets the block of acreage.  By contrast, under non-discretionary award regime, state authorities choose the company that will get the block.  Criteria for receiving a discretionary award range from fairly explicit to the extremely obscure, depending on the country concerned.  This method lets the government mould oil company behaviour to match its own goals.   In order to increase the likelihood of receiving competitive offers for acreage, governments solicit industry’s view as to the acreage of interest and then invite applications for some or all of the acreage, which have been suitably subdivided into blocks.  Seldom is the information made public about the number companies applying for each block.

 

Value creation in acquisition

 

The activities in the licence acquisition phase are to delineate, interpret and evaluate various prospects.  Competencies such as knowledge, skills of interpretation and imagination are the most crucial for performing this activity and thus create the most value for a firm.  It is on the basis of recommendations of its skilled professionals that the firm makes choices as to which licenses it should apply for.  In executing the choice, the firm either applies for the chosen license from the government or approaches the company which owns the desired license.  Ultimately getting the most prospective areas has been identified as the most value creating activity. 

 

Most decisions on prospect acquisition can be seen as the first of a number of separate, sequential decisions that may ultimately lead to the establishment of commercial production.  At each stage the company effectively has a decision to make as to whether or not to proceed in the light of the results achieved during the previous stage or to abort the prospect.  Generally, each further stage through which the prospect passes requires relatively greater investment stake.   In addition value in this phase is driven by reputation of being the actor with the competencies to perform the succeeding activities (finding, developing and producing crude oil) in a manner which is most efficient from the perspective of the decision makers.   Outstanding reputation in exploration also improves the firm’s ability to bid successfully for the most promising acreage and its ability to recruit the best professional. In this regard geographic specialisation becomes a way of differentiating firms which could ultimately become its competitive advantage.   

 Exploring for oil

The first step after obtaining a licence is that of conducting gravimetric and seismic surveys, heat flow measurements, radiometric and geo-chemical surveys and drilling of shallow bore-holes to identify commercial quantities of hydrocarbons in the acquired area.  Most of the specialised services and technologies required to carry out these activities - such as 3D seismic mapping - are procured from the supply industry.   Even though a realistic view of the subsurface is said to be the key to assess whether or not a correct exploration conclusion has been arrived at, the ultimate answer to the question whether or not oil is present beneath the surface is obtained only through drilling.  Once commercial quantities of hydrocarbons have been established in an area after drilling, the find is appraised using normal capital project appraisal techniques, such as the net present value (NPV) calculation.  When the project proves to be viable on the best assumptions of capital costs, oil prices, etc., the oil company (or a group of companies) takes the decision to develop the field.  When applying for licenses, gathering data through seismic shooting and exploratory drilling are the standardised information acquisition procedures that help the actors reduce risk in the exploration phase. 

 

Drivers of Value in Exploration

 

In exploration, the prime object is a basin, play or prospect with more or less uncertain petroleum resources that, when explored could become fields with proven reserves.  Object incorporation is the most important driver of value in exploration and is secured through the acquisition of the licence.  Drilling is the subsequent activity but it is difficult to gauge the relative performance of an individual actor because of the complexity and the variable nature of the drilling business.  But it is important for upstream actors who spend more than 50 percent of their operating budgets on drilling activities, to know how well they are performing in this activity relative to their peers. 

 

Some consulting companies evaluate critical aspects of their drilling performance compared to those of other players and to industry standards[1].   The evaluations are based on cost and time factors as opposed to finding hydrocarbons which relates to identifying the right place to drill.  Learning is an integral and explicit part of this phase and a key linkage to subsequent activities.  The sequence of activities is interrupted if drilling results appear to be inconclusive in the volume of recoverable resources present.  Overall performance and thus value in solving the problem of ‘finding commercial quantities of hydrocarbons’ depends on the quality of professionals within the firm because the data interpreting skills and experience of the professionals is the main factor driving the effectiveness in this phase.

Sharing and interrelationships between actors is also an important driver of value in the upstream sector.   Learning across projects (different licenses) and client problems (experience in exploring prospects offered by other clients) also drives value for a given actor.  Structural factors such as the extent of governmental involvement have also been found to have a great influence on value creation for petroleum exploration in producing countries. The government decides the pattern of licensing rounds, what is offered in them and to whom.  Apart from deciding the fiscal structure it is also involved in setting the frames for how many exploratory wells are to be drilled, restraining the choices available to the actors.   

 

Leverage of personnel is obtained through value that comes with years of experience within petroleum exploration.  Scale has some impact on exploration in terms of specialisation in methods and tools.  Only larger companies are perceived as technology leaders and able to perform their own R & D to develop for instance, their own proprietary tools[2]. 

 

Field Development 

 

When a prospect has been tested by appraisal wells and has found a commercial quantity of hydrocarbons, the development decision is taken by the company (or group of companies) that own the discovery.  A general observation of investment statistics is that investment on field development is by far the largest in upstream activities.  Additional seismic and petroleum engineering studies are usually made and more appraisal wells are drilled to obtain enough information to ascertain that the field has sufficient reserves to justify the major expenditures required to construct production facilities.  A team of geologists and petroleum engineers are assembled to decide the best possible scheme for developing the find.  This team analyses the data from the discovery and appraisal wells and from other sources and will build up a detailed picture of the extent of the reservoir, its reserves in place and its various characteristics such as porosity, permeability and pressure; this will enable a number of different schemes for the development of the reservoir to be considered.  Other factors such as the number and location of wells required the maximum daily volume to be handled, the oil: gas ratio expected, depth of water and governmental safety regulations are also taken into account. Economic analysts work in parallel to determine various development costs, oil price, tax and other assumptions required to complete the project.  Dependent upon the size of both the company and project and the management style of the company, this work could be done wholly in house or may be contracted out to service companies.  Petroleum field development is initiated by referral from exploration:  It is common to define appraisal as an element of the field development activity set.  Alternative development concepts are generated and evaluated then field development concept to be used is chosen.

A rough estimation of the cost structure in this phase illustrates that production drilling is the most significant cost-driver.  However, this is the activity that contributes the most in terms of value delivered.   The choice of the development design determines, to a large extent, the economic success of the production phase that follows. 

 

Drivers of Value in Development

 

Firms which are knowledge intensive such as upstream operators develop relationships within the corresponding business value system in field development through subcontracting.  The upstream actor subcontracts the development assignment to a service company, but retains ownership and control.  The resulting business value system is a network of relations and reputations of the contractor and the quality of its people. The skills and qualifications of the staff involved are now being ranked as such an important factor by companies that are willing to accept prices of up to 10 percent higher than the lowest bid.  The decision to develop an oil field (when and how) is the most important for which the ‘operator’ has to take major responsibility.  The sums involved are large and an operator who presides over a ‘development’ project that is well-executed and performs as or better than expected will find its reputation enhanced and could be rewarded with more operator ship titles. Operator ship titles are important not only to enhance the reputation of a company but also to attract the most talented people.  A talented person will find it much more satisfying to work for an active operator, than do ‘monitoring’ and ‘second-guessing’ work for  non-operator.  Thus it will often be easier for an operating company to attract and retain talent than it would be for a company that declared that it had no operating ambition.  Sharing and interrelationships between the upstream actor and the subcontractor within the business value system is an important driver of value in the development stage. Clear definition of the roles and responsibilities for actors in contractual relationships avoid duplication, assign accountability and enhance value created. Learning across projects (different concepts) also drives value for a given actor.  There are limited advantages of scale in development efforts.  There are more than quantitative differences between a $ 1 billion project and a $ 10 billion project; the $ 10 billion project could be similar to existing ones and the $ 3 billion project could require great ingenuity and novelty.  

Production

 

If all the assumptions and projections made in the development phase hold, production could be regarded as a fairly automatic process; however, such situations do not occur in real life.  When an oilfield has been developed and brought into production, economic and technical problems usually arise.  The need for the addition of reservoir energy through water or gas injection, the need to drill additional wells and the need for working-over producing wells are just a few of the frequently encountered technical challenges in the production stage.  The more difficult challenges are usually ‘economic’ in nature.  At a time of low oil prices, economic considerations usually take a much higher priority in upstream company management.   

 

Cost Drivers in Production

 

The production phase creates value by transforming the input (subsurface hydrocarbon deposits) into crude oil and value here, is derived by performing activities in a cost efficient way. Production installations involve large overhead costs incurred in the exploration and development stages of a project. Effective co-operation with contractors, technology, standardisation, reduced bureaucracy and uniform information management in these stages have consistently reduced capital costs per unit of production over the years.  A 20 percent reduction in production costs yields a saving of about $ 10-12 billion in net present value over a 10 year period.  The average contribution of the production phase to the break-even price of a typical field on the North Sea is about $4.5/bbl.  Of this, drilling of production and injection wells accounts for only $ 0.2/bbl, while the remaining is taken up by personnel related costs. Large overhead costs imply that scale and capacity utilisation is important drivers of production cost.  Utilisation of existing capacity that gradually becomes available on field installations and pipelines permits increased value creation for both owners and users of the infrastructure.  There are some locational advantages in production installations.  Fields that is near existing installations can be tied into the existing infrastructure as spare capacity becomes available thus reducing capital costs for a given project.  Location can also have an impact on the reservoir characteristics and hence the recovery factor.  Depth at a given location also has an impact on development and production costs.  The development of efficient infrastructure through sequencing of events will determine the efficiency with which petroleum may be brought from the reservoir to the market, and thus its value and recoverability.  The state may play a major role in assuring efficiency in petroleum resource management through policies on infrastructure. Interest for developing oil discoveries, is a result of a more cost effective petroleum industry and the fact that processing capacity will be available on existing installations.  These resources can with present-day technology and experience be tied into existing installations provided there is available capacity on processing plants, and it is considered safe from a safety point of view. It is important, however, for the licensees to develop a strategy which ensures an appropriately timed phasing-in of the discoveries, thus achieving optimum use of the existing installations.

 

While there is more to the debate on restructuring the oil & gas industry in India than just value creation, it may be wise to appreciate the distinctiveness of value creation logic in each stage. 

 

[email protected]

(Views are those of the author)

 

 

Russia holds the world's largest natural gas reserves, the second largest coal reserves, and the eighth largest oil reserves. Russia is also the world's largest exporter of natural gas and the second largest exporter of oil. During the last few years energy exports, primarily oil & gas, have fuelled the growth of the Russian economy which has surpassed the growth of all G 8 countries but the economy remains vulnerable to fluctuations in oil prices.

 

The government is attempting to restructure its energy industry while at the same time decrease its dependence on energy exports. Russia’s proven oil reserves of 60 billion barrels, though the largest outside the Middle East are just 5 per cent of the world total.  Most of the reserves are in Western Siberia, between the Ural Mountains and the Central Siberian Plateau. In the 1980s Russia produced nearly 12.5 million bpd but following the collapse of the Soviet Union in 1991, oil production started to decline falling to about half the peak level.  Several factors including the depletion of its major fields due to state administered production targets along with the collapse of the planned system may have influenced the decline. 

 

Privatisation of the industry in 1999, increase in oil prices along with the devaluation of the rouble helped to reverse the trend. In 2003 total liquids production touched 8.4 million bpd which was 10% more than the previous year and almost 40% higher than the level in 1998.  This made Russia the world's second largest producer of crude oil, behind only Saudi Arabia in 2003.

 

Expanding Russia's capacity to export oil in order to keep pace with the country's growing production is important to both the government and Russian oil companies. However, since crude oil exports via pipeline fall under the exclusive jurisdiction of Russia's state-owned pipeline monopoly, Transneft bottlenecks in the Transneft system make the company's export capacity incapable of meeting oil export demand. Recently, Russian oil producers have taken advantage of higher world oil prices and re-directed their surplus oil via railroad and river barge to external markets. The Russian government and Transneft have acknowledged the capacity problem and have taken careful steps towards developing new export infrastructure. At issue, however, is not only the direction and scope of enhancements to the country's export infrastructure, but also the potential role that private firms and investors may play in these projects, presumably at the expense of state-owned Transneft.

 

Both the Russian government and analysts agree that production should continue to grow, at least in the short term. However, it is unclear whether production will show the same momentum as before. In early years of the disintegration of the Soviet Union, western firms entered Russia as Russian energy firms, which were inefficient and short of capital seemed in desperate need of foreign help. However that was not a sustained development.  The government failed to pass laws to protect foreign investment in oil and gas production; together with Russia’s regional governments, it imposed high and arbitrary taxes. Russia’s oil and gas bosses educated in Soviet engineering and oil-drilling schools resented foreigners.

Efforts to sell Rosneft, an oil firm failed twice.  The government’s efforts to sell 5% of Gazprom, possibly to a foreign-backed consortium, reducing its stake in the gas monopoly to 35% did not materialize. BP lost about $ 200 million in an ill fated venture with a Russian company.  Rumors of Exxonmobil and Chevrontexaco investing in Russia have proved to be just that – rumors.  Elf Aquitaine, a French energy company pulled out of a planned alliance with Sibneft, a Russian oil firm. Even firms that have struck large deals in Russia in the past are thinking twice about further investment. BP spent $500m buying 10% of Sidanco; Royal Dutch/Shell and Gazprom formed a partnership that led to a $1 billion investment. Yet the same two western firms pulled out of rival consortiums bidding for Rosneft.  In April 2003 Yukos and Sibneft announced merger plans that would have created Russia’s largest oil company with reserves of 18.4 billion barrels and a production capacity of about 2.2 million bpd.  The $12-15 billion merger was approved by Russia’s Anti-monopoly agency but tax fraud allegations leading to the arrest of key figures of Yukos including Platon Lebedev and company head Mikhail Khodorkovsky put an end to that proposal.  

Despite President Vladimir Putin’s statement on December 23, 2003, that "The fuel and energy sector, overall, is the goose that lays the golden egg. Killing the goose would be insane, stupid and unacceptable" policy appears to be killing the goose.   Effective from August 2004 taxes on oil exports have been increased significantly; state controlled export infrastructure has also grown much faster than that of the private sector. It now appears that neither Russia’s government nor its firms are willing partners to private investment. 

Western firms prefer to spend their money on “production-sharing agreements”, a type of contract for exploiting oil and gas fields that insulates companies against changes in a country’s tax regime. To add to their difficulties, western firms have found themselves increasingly entangled in arguments between the government and the Russian industry. Russian politicians dislike the national oil bosses who are extremely wealthy. According to the politicians the country’s past energy privatizations were unfair, geared to enriching industry insiders. The energy firms, in turn, complain that the government is taxing them too heavily, and that it is expecting them to pay too much in new asset sales.

Even if the Russian energy sector is completely restructured and private investment encouraged, that would not mean an end to dominance of Middle Eastern oil.  First since Russian oil is mostly in the hands of the private sector, it cannot maintain excess capacity to match Saudi Arabia.  Shareholders of Russian firms will consider it a waste of money.  Russian oil is more expensive to produce. While it costs roughly a dollar to lift oil out of the deserts of Saudi Arabia or Iraq, $ 2.5 is required to lift Russian oil.  Many of Russia’s ports are frozen for most part of the year which means that it would be difficult to get Russian oil to the market quickly even if capacity is developed.  

 

Despite these challenges the Russian energy sector is attractive not just for Russians but also for foreign investors provided President Putin demonstrates that his policies for the energy sector are not actually insane.  

 

 

 

 

 

 

NEWS BRIEF

 

 

OIL & GAS

 

 

ONGC signs MoU with Karnataka for Rs 250 billion project

 

August 30, 2004. Public sector behemoth Oil and Natural Gas Corporation Ltd signed a MoU with the Karnataka Industrial Areas Development Board for developing the coastal special economic zone at Mangalore with investments in petrochemical and energy sector to the tune of over Rs 25,000 crore (Rs 250 billion). The MoU, which was also signed by Kanara Chamber of Commerce and Industry (KCCI), is aimed at giving a boost to the economic and industrial growth of the coastal region in the state through an accelerated and planned approach to the development of the SEZ at Mangalore.  The MoU was for an initial period of two years. The project would take about three to five years to begin from the 'zero date' (the date when all clearances from both the state and Centre are obtained). ONGC, he said, intends to put a Liquefied Natural Gas (LNG) terminal at Mangalore, for importing around 10 to 12 million tonne per annum (MTPA) of LNG, besides setting up downstream projects and involving private firms in other projects.

 

IOC to invest Rs 3.97 billion for laying pipelines

 

August 26, 2004.  State refiner Indian Oil Corp plans to invest Rs 397 crore (Rs 3.97 billion) in laying two new petroleum product pipelines, Petroleum Minister Mani Shankar Aiyar said. IOC plans to lay a 270-km branch pipelines to Raxaul and Baitalpur from Barauni-Kanpur product pipeline at an estimated cost of Rs 170 crore (Rs 1.7 billion). It has also planned a 274-km line from Koyali to Ratlam at an investment of Rs 227 crore (Rs 2.27 billion).  The two pipelines would be completed in 24 months from investment approval. The company is to complete Rs 352.49 crore (Rs 3.52 billion) Sidhpur- Sanganer line by November and the Rs 75.96 crore (Rs 7596 million) 160-km Panipat-Rewari pipeline by next month. The Chennai-Trichy-Madurai pipeline will be completed by July 2005 at an investment of Rs 363.21 crore  (Rs 3.63 billion)  while the 112-km Koyali-Dahej pipeline would be completed by March 2006. Branch pipelines to Ajmet from Sidhpur-Sanganer pipeline Rs 20.92 crore (Rs 209.2 million) and to Chittaurgarh Rs 82.58 crore (Rs 825.8 million) would be completed by January 2005 and February 2006. 

Gulf Oil plans to boost exports

 

August 26, 2004. Gulfoil Corporation Ltd has set its eyes on exports to enhance the profitability of the lubricants division. Concentrating on the ASEAN markets and Africa, Gulf Oil expects to increase exports to 10 per cent of turnover in the next three years. The Rs 240-crore (Rs 2.4 billion) division now exports lubricants worth a little over Rs 2 crore. A Hinduja group company, Gulf Oil, has registered a turnover of Rs 450 crore (Rs 4.50 billion), including both the lubricants and explosives business during the last fiscal. Apart from direct exports, a substantial part of overseas trade is routed through the Gulf's outfits in Bangladesh and China.  At home, the company has set a steep target of 35 per cent sales growth in this fiscal. While major campaign initiatives are underway to enhance its brand equity, efforts are on to tie up with automotive component manufacturers for cross leveraging of distribution network.

 

IOC to invest Rs 40 billion to hike refinery capacity

 

August 31, 2004. Indian Oil Corporation (IOC) is planning to upgrade manufacturing capacities at its Gujarat refinery by investing Rs 4,000 crore (Rs 40 billion) over a period of two years. While around Rs 3,000 crore (Rs 30 billion) would be spent on low sulphur high stock (LSHS) up gradation project, the remaining Rs 1000 crore (Rs 10 billion) will be invested for upgrading its production of motor spirit quality as per the Euro-III standards. The company is planning to set up a new unit for LSHS, which is fuel for power generating companies, from the residue of crude oil that it gets from ONGC’s north Gujarat pipeline. IOC’s Gujarat refinery, which processes 3 lakh (300,000) tonnes of domestic and imported crude oil per day, is also planning to upgrade its motor spirit quality as per the Euro-III and BG-II standard.

 

 

GSPCL plans operations abroad

 

August 31, 2004. Gujarat State Petroleum Corporation Ltd (GSPCL), the country’s only state government enterprise in the oil and gas sector, plans to extend operations outside India, mainly in the exploration and production (E&P) sector. The Rs 1000-crore (Rs 10 billion) company, which recently discovered huge oil reserves at Dholka on the outskirts of Ahmedabad city, has finalised plans to explore all 16 wells under the Krishna-Godavari (KG) basin in the next two-three years. It will use the proceeds from its proposed initial public offering to invest around Rs 4000 crore for the purpose. GSPCL has also recently started the business of regassified liquid natural gas (RLNG) as a gas supplier. Its has entered into a contract with Gail India to purchase RLNG which it would sell through the pipeline network of its wholly-owned subsidiary, Gujarat State Petronet.   

 

IOC plans Rs 250 billion petrochemicals thrust

 

August 30, 2004. Indian Oil Corporation (IOC) has planned a mega foray in petrochemicals with an estimated investment of Rs 25,000 crore (Rs 250 billion).  The company intends to utilise the streams available from its various refineries for forward integration. The concentration would, however, be on Panipat refinery in the north and the proposed Paradip refinery in the east. The entire investment would be phased over eight years. In fact, IOC is spending Rs 10,852 crore (Rs 108.52 billion) in petrochemicals alone between 2002 and 2007, which is about 45 per cent of the investment of Rs 24,399 crore (Rs 243.99 billion) planned during this period. Reliance, along with IPCL, holds over 60 per cent share of the market, followed by Haldia Petrochemicals Ltd (HPL) and GAIL India. IOC first intends to make stronghold in the north and east before taking Reliance head on in the west where RIL and IPCL are located. 

 

MRPL plans Rs 13 billion upgrade

 

August 31, 2004. Mangalore Refinery and Petrochemicals (MRPL) is planning an investment of Rs 1,300 crore (Rs 13 billion) on plant and product up gradation.  Investments on MRPL would be made over next couple of years in phases up to 2005-06. MRPL with a capacity of 9.7 MMTPA, around a tenth of the total domestic capacity, was presently running at 120% of its production capacity at an annualised rate of 12 MMTPA. ONGC, which took over 51% equity share and management control in March last year, has now increased its equity to 71.6%.  ONGC, with marketing rights to retail diesel and petrol through 1,100 retail outlets and 23% stake in the Rs 667 crore (Rs 6.67 billion) Mangalore-Hassan-Bangalore pipelines involving a length of 360 kms, was fully poised to expand the economic supply envelope of value-added refined products in Karnataka. 

 

 

Petronet wants RasGas to advance LNG supply

 

August 25, 2004. Petronet LNG Ltd (PLL) is negotiating with Ras Gas of Qatar to start delivery of 2.5 million tonne liquefied natural gas (LNG) consignment three months ahead of the schedule. Ras Gas has commitment to start supply of this parcel of LNG to PLL from January 2005. Petronet, is however, trying to pursue Ras Gas to start delivery from October itself.  If the Qatar Company agrees, it would give PLL close to one million tonne of extra volume during the October-December quarter, over and above the 2.5 million tonne LNG parcel, which Ras Gas is already supplying at Dahej for PLL. The company is trying to bring the cargo ahead of schedule as the second LNG tanker, ‘Rahi’, being manufactured by Daewoo Shipbuilding and Marine Engineering of Korea, is almost ready. Even though PLL has agreement to take delivery in December, the company intends take it in September. 

 

 

IBP, Petronet LNG sign moc for virtual LNG pipeline 

 

August 27, 2004.  IBP Co Ltd, an Indian Oil group company, and Petronet LNG Ltd have signed a memorandum of collaboration (MoC) for supply and distribution of liquefied natural gas (LNG) through a system of virtual pipeline using cryogenic containers.  This will enable even direct use of LNG at the customer’s end using cryogenic technology. Although IBP is a petroleum-marketing company, it has expertise in cryogenic equipment-manufacturing and makes cryogenic containers for oxygen, acetylene and argon gases, as well as for preserving bull semen for artificial insemination.  IBP has already tied up with world cryogenic technology major Chart Industries Inc, USA, which would provide technological and collaborative support to IBP for developing the LNG distribution system throughout the country.

 

Petroleum ministry invites bids for gas pipeline project 

 

August 30, 2004. The petroleum and natural gas ministry has invited expressions of interest from companies for participation in the common carrier gas pipelines project to be laid by the Gas Transportation and Infrastructure Company Ltd, a wholly-owned subsidiary of Reliance Industries. The project includes the 569-km Kakinada-Hyderabad section, the 473-km Hyderabad-Uran section and the 467-km Uran-Ahmedabad section while the originating point would be at the gas treatment plant at Gadimoga near Kakinada in Andhra Pradesh.  The project also includes the 664-km Goa-Hyderabad pipeline, which would pass through Goa, Karnataka, Maharashtra and AP. The design capacity of the above pipelines would have 25 per cent capacity to be offered on common carrier basis for use by anyone other than the owner and those taking capacity. The pipeline projects would be financed on 2:1 debt equity ratio but the exact financing would be worked out after taking into account the interest expressed and commitment provided by the other users. The interested parties would have to enter into a ‘take and pay’ contract or any other mutually agreeable contract with the owner for the usage of the proposed pipelines. The pipelines are scheduled to be commissioned in 36 months from the date of formal announcement and the ownership of the pipelines would be that of Gas Transportation and Infrastructure Company.

 

 

Government may sell stake in OIL to IOC 

 

August 27, 2004. The Indian government is considering a move to sell its majority stake in exploration firm Oil India Ltd (OIL) to the country’s largest refiner, state-run Indian Oil Corporation (IOC). The proposal was a part of a broader plan to restructure state-run energy firms to create two or three large companies. Oil India Ltd (OIL) is an exploration firm based in Assam. State-run firms were competing with each other for investments in oil and gas projects abroad and spending heavily to upgrade petrol stations to attract customers, but were less enthusiastic about providing kerosene and cooking gas in rural areas. Another option being examined is to merge refining giants Hindustan Petroleum Corp Ltd and Bharat Petroleum Corp with the country’s largest exploration firm, Oil and Natural Gas Corp.

 

Government plans strategic oil reserves

 

August 25, 2004. The government plans to build 5 million tonnes of strategic crude oil reserves, minister of petroleum and natural gas Mani Shankar Aiyar told the Rajya Sabha. It is also considering taking oil projects’ equity abroad, he said. He said that the strategic storage would be in addition to the existing storage of crude oil and petroleum products with the oil companies. This would facilitate oil supply in emergency situations, when there may be disruption in normal supply, he added.

 

POWER

 

 

Petronet gas for NTPC power plant

 

August 25, 2004. NTPC has approached Petronet LNG to supply re-gasified LNG through its pipelines to its power plants. It is also in talks with Reliance to push for an early gas supply schedule. NTPC has written to LNG suppliers like Petronas, Oman gas, Rasgas, Shell and Petronet LNG, among others to source around 0.7m tonnes of LNG and meet the shortfall in fuel supplies. This would translate to a requirement of about 6-7m cubic metres of gas per day. NTPC, which has a total gas-based capacity of 4,000 mw is also in talks with Reliance to push for an early gas supply schedule for the Kawas and Gandhar power plants in Gujarat.  The original schedule for gas supplies by Reliance has been fixed for mid ’07. However, officials in NTPC confirmed that given the progress of power plants and the need to add more capacities at a higher rate, the company is exploring possibilities of getting committed gas from Reliance’s KG basin by December ’03.

 

 

Bhilwara Group to seek foreign partner

 

August 24, 2004. The LNJ Bhilwara Group has two hydro projects - 90 MW Malana Power project which has been operational for the last three years and a 200 MW Allan Duhangan project, under a new company called AD Hydro Power Ltd.  The group has now decided to offload up to 49 per cent stake in Malana Power to a foreign partner. Also, Malana will acquire 90 per cent stake in AD Hydro, while the remaining 10 per cent will be offloaded to the World Bank arm, International Finance Corporation.  The Allan Duhangan project is worth Rs 900 crore (Rs 9 billion) and will be funded with 65 per cent debt component.

 

 

Orissa plans hydro project expansion

 

August 26, 2004. The state government has decided to construct extended reservoirs to facilitate expansion of a few existing hydro electricity projects including Balimela, Hirakud and Chiplima. This decision was taken at a high-level meeting, chaired by the energy minister, Mr Surya Narayan Patro. Two units of 175 mw and 75 mw each would be set up at Balimela and extended reservoir would be built at Surlikonda in Koraput.

 

Ten NTPC plants bag performance awards

 

August 27, 2004. Ten power stations of National Thermal Power Corporation have bagged the 'Ministry of Power Awards' for outstanding performance. The awards were conferred by President A P J Abdul Kalam at a function in New Delhi recently. Out of the 24 power stations that have bagged the Gold Shield, 10 belong to the NTPC.  These include Ramagundam, Korba, Rihand, Singrauli, Badarpur, Dadri, Unchahar, Vindhyachal, Anta Gas and Simhadri. The awards have been presented for four years from 2000-01 to 2003-04. The awards have been instituted by the Central Electricity Authority to inculcate a competitive spirit and to motivate the power utilities to achieve a high level of performance. 

 

Chinese company bids lowest for Bengal power plant

 

August 30, 2004.  Power projects worth over Rs 3,000 crore (Rs 30 billion) are being put up with amazing speed by a Chinese company in West Bengal. The Chinese have brought in their ruthless cost efficiency by committing to set up 900 mw (3 x 300 mw) at Rs 2.6 crore (Rs 26 million) per mw.  This is way below the benchmark cost offered by all global power developers who forayed India since ’94 when the power sector was opened up. Most power projects, currently being considered for financial closure, are estimated to come with a total cost of around Rs 3.5 crore to Rs 4 crore (Rs 35-40 million) per mw.  The Chinese power company’s bid to set up the power plant at a cost way below the “accepted costs of today” could get domestic equipment companies to take a relook at their costs. The bid is being considered highly competitive and aggressive as it comes as a time when raw material costs like steel are at a high. The Chinese power equipment major, Dongfang Electric Company, will be developing the project on a turnkey basis. The project was bagged by the Chinese firm through a transparent open bidding process, beating MNCs like Alstom, among others. The Chinese equipment company ends up adding a yearly capacity of almost 10,000 mw.

 

Himachal clears Rs 25 billion hydel project

 

August 28, 2004. The Himachal Pradesh government cleared the 400-MW Rampur hydro-electric project, to be executed by the state government and public sector Satluj Jal Vidyut Nigam Ltd (SJVNL). The project is expected to be built at Rs 2,500 crore (Rs 25 billion). The state government will have 30 per cent equity.  The government also approved the allotment of 27 small hydro projects, with an aggregate capacity of 88 MW, to 27 private sector companies. These allotments are expected to bring an investment of Rs 528 crore (Rs 5.28 billion) over the next five years, besides bringing in royalties for the state government at 10 per cent after 15 years of commissioning. 

 

Nuclear power can be as cheap as Rs 3.22 a unit

 

August 27, 2004. The country's nuclear establishment has promised to make available electricity at a much lower cost than power from conventional sources. The 500-MW Prototype Fast Breeder Reactor (PFBR), under construction at Kalpakkam, is expected to produce power for a price of Rs 3.22 a unit in the year 2011. The Rs 3.22-a-unit is calculated on the assumption that the plant would operate at 60 per cent of its capacity, but officials are confident that it would perform better. The next set of fast breeder reactors — there are four on the anvil — will be able to produce power for a price of Rs 2.40 a unit because, the cost of equipment would be lower because orders would be placed in larger volumes in addition to standardization of design.  The time taken for construction would be shortened, thanks to the experience gained at the PFBR project. Earlier, nuclear power plants took 7-8 years from start to finish. Better financial package would help bring down project cost and hence the cost of electricity produced.

 

 

 

Reliance eyeing power line to Delhi’s VIP area 

 

August 25, 2004. Reliance Energy has sought a licence to distribute electricity to the New Delhi Municipal Council (NDMC) area in the Capital. A large part of Lutyens’s Delhi lies in the NDMC area, where India’s political elite lives and works. The move rides on Reliance’s forthcoming power generation plans for the national Capital region market through a gas-based 3,000-MW plant in Dadri, Uttar Pradesh. Reliance has already applied for a licence with the Delhi Electricity Regulatory Commission (DERC).

 

The move marks the emergence of a second player in the distribution business. With the “open access” provisions in the Electricity Act, 2003, big cities in India are expected to see two, if not more, distribution networks for power supplies in the same area. There is, however, a 5-year time frame for open access in distribution to become mandatory. In the absence of any policy guidelines on open access in distribution, private players like Reliance Energy and Tata Power are opting to lay parallel networks instead. Both companies have already applied for electricity distribution licences in cities like Pune, Nasik, Aurangabad and Nagpur, by putting up parallel distribution networks.

 

Kalam urges thermal power plants to cut T&D losses

 

August 25, 2004. The President, Dr A.P.J. Abdul Kalam, has asked the thermal power stations to focus on reducing the transmission and distribution (T & D) losses from the existing 31,000 MW to 12,000 MW in phases within the next three years. Dr Kalam said that the cost of reducing such losses would be only a small percentage of the cost of generating 19,000 MW of additional power. Dr Kalam advised the Power Ministry to build a 500 MW thermal plant during the Tenth Plan designed to use exclusively either bio-diesel or solar energy.

 

 

NTPC to achieve Rs 1400 billion turnover by 2017 

 

August 25, 2004. The state-run National Thermal Power Corporation (NTPC), whose initial public offer (IPO) will be launched on September 23, proposes to achieve the group turnover of a record Rs 1,40,000 crore (Rs 1400 billion) by 2017. NTPC’s corporate plan also includes becoming Fortune 500 company and an Indian MNC with presence in many countries, increasing the generating capacity 56,000 mw from the present level of 20,000 mw with a well diversified fuel portfolio. Thermal power generation would rise to 42,000 mw, hydro (11,000 mw), nuclear (2,000 mw) and non-conventional fuels/distributed generation (1,000 mw). The Corporation would regularly review share of coal based generation based on technology developments and changes in availability/pricing of alternate fuels.

 

 

Gujarat to rework PPAs for cheaper power

 

August 26, 2004. In a move to further reduce power tariffs, the Gujarat government plans to renegotiate its power purchase agreements (PPAs) with private producers in the state. The state wants the tariff to come down to Rs 2.20 per unit from about Rs 2.50 at present.  The state power ministry has also drawn up an ambitious programme to generate another 5,000 mw power in the next 3-4 years. Of this, about 30% is expected to be put up by private players, while the rest will be put up by state and central utilities. Torrent will be setting up a 1,000-mw plant, while another IPP is negotiating setting up a 600-mw plant.

 

CNG Act in Gujarat

 

August 26, 2004. Gujarat would enact a CNG Act by early next year, which will make it mandatory for public transport vehicles to convert to CNG in phases.  Ahmedabad, Surat and Baroda, the state’s most polluted cities, will be the first in Gujarat to switch over to CNG. First, the three-wheelers (auto-rickshaws) will be made to convert to CNG, followed by other public transport vehicles like taxies and buses, and finally private vehicles. Gujarat would be expanding the gas pipeline grid to Rajkot and Jamnagar by next year, and to Bhavnagar and Pipavav in two years. Currently, Surat, Ahmedabad and Baroda are on the gas pipeline grid. The Adani Group and BPCL are implementing gas distribution and CNG projects in Ahmedabad and Gandhinagar. Mr Dalal said state-run gas utility, GAIL, had been given a licence for gas distribution in Rajkot

 

Orissa set to become a powerhouse by 2010

 

August 26, 2004. Orissa will emerge as the mega power house of the country by 2010 with at least a dozen hydro and thermal power plants, entailing an investment of Rs 30,000 crore, (Rs 300 billion) set to generate about 8,000 mw. The state government, battling a major financial crisis, has decided to invest around Rs 270 crore (Rs 2.7 billion) in three installments in Orissa Power Generation Corporation (OPGC), in which it holds a 51% stake. This is the first major investment decision by the state government in the last decade. Chief minister Naveen Patnaik kicked off the state’s investment plan by laying the foundation stone of 3-4 units of 250 mw each at Ib valley. The cost of these two units is pegged at Rs 1,800 crore, (Rs 18 billion) and the projects will go on stream within 33 months of the financial closure in May next year.

 

 

 

 

OIL & GAS

 

 

ChevronTexaco announces significant natural gas discovery in Australia

 

August 24, 2004. ChevronTexaco Corp. announced a significant natural gas discovery at its Wheatstone-1 well, located offshore 110 miles west-northwest of Dampier in Western Australia. A production test on the well, in retention lease WA-17-R, established a flow rate of 54 million cubic feet per day, which was constrained by rig equipment. The lease is held 100 percent by ChevronTexaco affiliates ChevronTexaco Australia Pty Ltd and Texaco Australia Pty Ltd. The Wheatstone Field extends north into an adjacent permit, WA-253-P, where ChevronTexaco affiliates also hold a 100 percent interest.

 

Shell considers extra heavy oil deal in Venezuela

 

August 24, 2004. Anglo-Dutch oil major Royal Dutch/Shell and Venezuelan state oil firm PDVSA are studying a potential new project to turn extra heavy crude reserves from Venezuela's Orinoco region into lighter oil.  The technology under discussion is geared toward increasing the recovery of extra heavy crude from Venezuela's vast Orinoco hydrocarbons region for conversion into commercial grade oil. Crude from the Orinoco deposit is too heavy to be processed in normal refineries and must be blended with lighter grades or upgraded into synthetic crude for export. The two companies could enter into a joint venture within 18 to 24 months if the recovery technology is successful. Foreign companies are already partnered with PDVSA in four projects to upgrade extra heavy Orinoco oil into lighter synthetic crude. Venezuelan officials are hoping to announce a new bidding round for Orinoco projects later this year. Foreign companies consider the region the best bet for fresh investment in Venezuela under a 2001 Hydrocarbons Law. Analysts and international firms say the terms offered under the new law, including a mandatory majority state stake in new deals, are unattractive for fresh investment.

 

Ecuador approves of oil drilling in Amazon reserve

 

August 25, 2004. Ecuadorian President Lucio Gutierrez gave Brazil's state-run oil firm a green light to start drilling inside an Amazon jungle reserve, prompting an immediate ourt challenge by environmentalists. Gutierrez made the announcement during a visit by Brazilian President Luiz Inacio Lula de Silva. The Ecuadorian government approved plans by Petroleo Brasileiro, or Petrobras, to drill in a jungle area designated a protected biosphere reserve by UNESCO in 1989. The area, called Block 31, is believed to hold 230 million barrels of oil. Ecuadorian environmentalist and indigenous groups warn that Wednesday's deal means three foreign oil companies now will be able to drill virtually throughout the reserve.

 

 

Kahili gas field production commences in New Zealand

 

August 25, 2004. Austral Pacific Energy Ltd. reports that production commenced on August 21 from the Company's Kahili-1A well in onshore Taranaki, New Zealand. NGC, the owner and operator of the Kahili Separation Plant (KSP) and purchaser of the gas, is presently commissioning the facility; and consequently choke sizes are restricted at present, and a stable production regime has yet to be established. On August 24, the first day of extended production, an average production rate on a 12/64" choke was 2.2 million cubic feet per day of raw gas, with a condensate (light oil) to gas ratio in excess of 60 barrels per million cubic feet, and a surface flowing pressure in excess of 2,300 psi. Gas is now flowing from KSP along the 8 km (5 mile) pipeline linking it to NGC's regional LTS pipeline.

 

Shell to spend more on European exploration

 

August 25, 2004. Oil giant Royal Dutch/Shell announced an increase in capital investment for 2004 in European exploration and production, as it looks to recover from an earlier reserves scandal. Shell said it had increased capital investment for its European exploration and production business by $150 million to $1.8 billion. The planned spending in this area is part of previously announced proposals to have a total capital investment of $14.5-$15 billion for 2004.

 

Indonesia will not extend Exxon's contract in Cepu

 

August 25, 2004. Oil major Exxon Mobil Corp will not get an extension on its contract to operate in Cepu, the top official at Indonesian oil company Pertamina said. "We will issue the letter this week. We will not extend Exxon's contract," Widya Purnama, the newly appointed Pertamina president director said. 

 

Exxon Mobil back in Colombia searching for oil

 

August 26, 2004. An Exxon Mobil Corp. affiliate has signed a deal to search for oil off Colombia's coast, marking the U.S. oil company's return to exploration in the Latin American country after 11 years. Under the deal, the Exxon affiliate together with Colombia's state-owned Ecopetrol and Brazilian state oil firm Petrobras will hunt for oil over the 11 million-acre Tayrona block off Colombia's northern coast in the Caribbean Sea. Exxon Mobil and Petrobras, which has experience exploring in deep water, both have a 40 percent stake in the block while Ecopetrol has a 20 percent interest. The deal is a boost for the Colombian government, which is eager to reverse a trend of falling output that could force the country to become a net oil importer by 2009. For Exxon, it offers the promise of a new source of oil as the company, like its peers, searches for oilfields outside North America.

 

U.S. backs plan to develop Alaskan oil fields

 

August 30, 2004. Federal officials gave tentative approval to a plan by ConocoPhillips and partner Anadarko Petroleum Corp to develop five satellite oil pools around the oil-rich Alpine field on Alaska's North Slope. The U.S. Bureau of Land Management issued a final environmental impact statement recommending that the companies be allowed to go forward with developing the satellites, located in the northeastern corner of the National Petroleum Reserve-Alaska and in the Colville River delta along the reserve's edge.  The satellite fields will provide 330 million barrels of oil, according to the BLM, and continue the oil industry's westward progression on the North Slope. Environmentalists have criticized the Alpine satellite plan as a rollback of environmental protections promised during the Clinton administration. If the fields are approved and developed, they would provide the first commercial oil production ever in the Indiana-sized petroleum reserve. The large land mass was set aside in 1923 for its energy potential but, until recently it has been ignored in favor of the region to the east, around the giant Prudhoe Bay field. The BLM said it expects production from the five new fields to start in 2006, supplementing production from the 429-million-barrel Alpine field. Alpine, the North Slope's westernmost operating oil field has a daily output of about 100,000 barrels.

 

OPEC promises to add output

 

August 31, 2004. OPEC is doing all it can to stabilize the world oil market and will increase spare output capacity by about one million barrels per day in the next few months, the cartel's president said. Oil prices fell following the OPEC announcement and a cease-fire declaration by the militant Iraqi cleric Moktada al-Sadr, whose militia has been battling U.S. and Iraqi troops.  "OPEC is doing everything it can to restore order and stability to the market, with a reasonable price that is acceptable to producers and consumers alike," Purnomo Yusgiantoro, president of the Organization of Petroleum Exporting Countries, said in a written statement from Jakarta. Purnomo said OPEC had as much as 1.5 million barrels per day of spare production capacity. "In response to expected demand growth in the near future, member countries have plans in place to further increase production capacity by around one million barrels per day toward the end of this year and into 2005," the statement said. "In addition, plans for additional capacity expansions are available and could be enacted soon," he added. "However, this capacity would, typically, become available around 18 months after commencement of this process." OPEC is estimated to be pumping close to 30 million barrels each day, the highest level since 1979, as prices have surged, hitting a record $49.40 a barrel on Aug. 20.

 

Thailand’s PTTEP interested in exploring oil and gas in Iran

 

August 30, 2004. PTT Exploration and Production (PTTEP) wants to start digging for oil in Iran and Libya as part of a plan to double oil and gas production in the next five years. PTTEP would seek more investments abroad in a bid to double production.  The strategy conforms to the government’s suggestion that PTTEP invest more overseas, increasing production to eventually surpass the country’s oil and gas demand. Investment in the next five years will be raised from the current Bt 77 billion.  The focus area for expansion would continue to be the Middle East and North Africa: Oman, Iran, Algeria and Libya. The company will bid for an oil-exploration block in Iran this year and explore opportunities to enter Libya.  

 

Apache logs 2 gas finds in Egypt 

 

August 27, 2004. Apache Corp.'s latest two discoveries in Egypt's Western Desert tested at a combined rate of 70 MMcfd of natural gas and 2,330 b/d of condensate from prolific deep Jurassic sands. The Mihos-1X discovery on the Matruh concession, which the company operates with a 100% contractor-interest, logged 191 feet of net pay in the Alam El Bueb (AEB) Cretaceous and Jurassic Upper and Lower Safa horizons between 12,350-15,700 ft. Workers perforated the Lower Safa at 15,385-420 feet, testing at a daily rate of 41.8 MMcf of gas and 1,419 bbl of condensate on a one-inch choke with 2,378 psi of flowing wellhead pressure.

 

OVL awaits approval from Australian government

 

August 30, 2004.  India’s ONGC Videsh has picked up a 55% stake in an offshore oil block in Australia. In the event of a discovery, OVL will get to recover the cost of the exploration. The produce, thereafter, will be shared among the partners in proportion to their shareholding. This is ONGC’s first foray into the Australian oil and gas industry. Incidentally, Australia, which is the eighth market for OVL, is a net oil importer. OVL has oil and gas assets in Myanmar, Vietnam, Iran, Iraq, Syria, Libya, Sudan and Angola.  OVL signed the farm-in agreement on August 27.  The acquisition will become final, once the government of Australia approves it. So far, ONGC has invested more than $2bn in oil exploration ventures overseas, including Russia and Sudan. The company plans to annually spend $1.08bn in overseas exploration in the next three years. India imports about 70% of its crude oil requirement, and ONGC’s strategy has been to acquire crude equity overseas to ensure crude security.  Antrim, which currently holds 87.5% stake in the block, estimates up to 500m barrels of recoverable oil.

 

China mulls $ 6 billion coal liquefaction project

 

August 25, 2004. China is mulling a six billion-dollar coal project with South African company Sasol that could give the energy-hungry mainland an additional six million tons of oil annually. In September a Sino-South Africa team will begin studying the feasibility of building two coal liquefaction production bases in northern Shaanxi Province and Ningxia autonomous region. Coal liquefaction is the conversion of coal into synthetic fuels. Liquid and solid products from coal can be used for fueling vehicles, power generators as well as yielding materials for chemicals. China's increasing dependency on Middle East oil and rising crude prices have spurred a new sense of urgency in the country to guarantee its energy supplies as the economy continues to expand at record pace. A net importer of petroleum products since 1993 and of crude oil since 1996, China is reliant on overseas producers for one third of its demand. To reduce its reliance on foreign crude oil, China started coal liquefaction efforts in 2001 and has managed to keep down what are generally considered expensive production costs to 20 dollars per barrel. China is interested in coal liquefaction on a large scale as the country's coal reserves of some one trillion tons account for 70 percent of its total energy reserves.

 

Sri Lanka to go ahead with Bharat Petroleum deal

 

August 25, 2004. Sri Lanka has said it will go ahead with its deal with Bharat Petroleum Corporation in oil retailing in the island nation despite opposition from the Marxist JVP, or People's Liberation Front, in the coalition government  Sri Lankan Finance Minister Sarath Amunugama said BPCL was willing to pay $50 million for a 49 per cent stake in the third petroleum distribution company to be set up using assets of the state-run Ceylon Petroleum Corporation (CPC). Asserting that it was "not privatisation", he said "BPCL is also a state-owned entity in India and the money from the deal will go to retire debt of the CPC and make it viable". A part of CPC assets have already been sold to Indian Oil Company (IOC) which is the second petroleum retailer in the island after CPC. The previous right-wing United National Party (UNP) which invited the IOC to enter the market here had identified a Chinese company, Sinopec, to be the third player in the island with full ownership of the new company.

 

$ 3.5 billion refinery deal agreed in China

 

August 26, 2004. Exxon Mobil, China's Sinopec and Saudi Arabia's Aramco reached agreement on design work for a $3.5 billion expansion of a refinery in China and the addition of a chemical complex. Fujian Petrochemical said in a joint statement the companies had agreed to jointly fund what they called front end loading design activity. The concern is jointly owned by China Petroleum Chemical Corporation (Sinopec), the Fujian government, along with ExxonMobil China Petroleum and Petrochemical and Aramco Overseas. The work includes completing initial engineering and design, selecting contractors, finalising cost estimates and the development of the pre-ordering of long-lead time equipment. The parties will then make a final decision on joint venture formation and project construction. Fujian Petrochemical will hold a 50 per cent stake in the integrated project joint venture if it is formed, with ExxonMobil and Saudi Aramco each holding 25 %. The project would result in a world-class integrated refining and chemicals complex located at Quangang in southeastern Fujian province. ExxonMobil, Sinopec and Saudi Aramco also agreed to submit a joint feasibility study for a fuels marketing joint venture in Fujian to the Chinese government. 

 

Shell, Sinopec in China retail venture

 

August 30, 2004. Royal Dutch/Shell Group said it would jointly operate 180 gas stations in China by the end of 2004, the second foreign oil major after BP to enter the country's huge but tightly controlled retail market.  Shell's joint-venture with state refiner Sinopec Corp would eventually run 500 retail outlets in eastern Jiangsu province, with total investments of $187 million.  Sinopec Corp, which announced a near doubling in second-quarter net profit to 8.14 billion yuan ($983 million), would hold 60 percent in the joint-venture to be based in the eastern city of Nanjing, the companies said. Anglo-Dutch Shell would hold 40 percent.  The joint-venture would start operations in Suzhou city, where about 180 service stations were planned by the end of the year with another 100 sites each in Wuxi and Changzhou city planned to open by end-2005. Some sites would be acquired or leased from Sinopec's existing retail network but the joint venture said it also planned to develop new sites. Sinopec would supply all fuel to the joint venture. But Shell still lagged rival BP in the race for a piece of the lucrative Chinese market.

 

China, Kazakhstan mull cross-border gas pipeline

 

August 25, 2004 China and Kazakhstan are mulling construction of a multi-billion dollar natural gas pipeline from the Central Asian nation to China's western Xinjiang Autonomous Region.  If built it would link with China's West to East pipeline which will pump 12 billion cubic metres of natural gas from the Tarim Basin in Xinjiang to Shanghai, some 4,000 kilometres (2,400 miles) away.  The Sino-Kazak trunk would give China access to gas fields in western Central Asia as a back-up to the West to East line and is considered a further step toward meeting the country's long-term energy needs. China and Kazakhstan earlier this year agreed to a separate three-billion-dollar deal to build the second-phase of a 3,000-kilometre (1,860-mile) oil pipeline.  It is expected to eventually pump 20 million tonnes of crude oil to western China. The Sino-Kazak gas pipeline would also cost billions of dollars although the exact price tag is not known. In the long term, the pipeline may extend further west towards Uzbekistan and Turkmenistan, and may be connected with grid conduits in Russia and Iran, creating a pan-Asian global energy bridge. 

 

China's Guangdong to import 10 MTPA LNG from 2010

 

August 25, 2004. The southern Chinese province of Guangdong will import 10 million tonnes of liquefied natural gas (LNG) a year from 2010 to meet strong demand. China is building its first LNG terminal in Guangdong, an industrial power house. The first phase of the project will receive 3.7 million tonnes of the super-cooled, compressed natural gas per year from Australia when it is completed in 2005. China National Offshore Oil Corp. (CNOOC Group), which owns 33 percent of the Guangdong project, said construction of the second phase of the project had already started. BP has a 30 percent stake in the terminal.  Energy-thirsty China is also building its second LNG terminal in Fujian, which will import gas from the BP-led Tangguh gas field in Indonesia.  China, which is planning several other terminals along its coast, aims to boost use of natural gas to 7 percent of its energy mix in 2010 from 3 percent. The U.S. government Energy Information Agency estimated China's natural gas consumption would rise at a compound annual growth rate of 8 percent between 2002 and 2025.

 

China to open gas pipeline 

 

August 31, 2004. China will formally open a major west-east gas pipeline, four months ahead of schedule, with operator PetroChina having tied up most of the supply contracts with customers, company officials said. The $8.5 billion, 4,200km project will channel natural gas from the Tarim basin on China's remote west to Shanghai and the booming eastern regions. China's top state oil and gas firm PetroChina will officially open the 2,330-km western sector tomorrow. It had earlier planned to start the western section in January 2005.The 1,660km eastern sector, which runs from Shaanxi province to Shanghai, is pumping about four million cubic metres of gas a day, since it began operations last October. That would represent two thirds of the pipeline's total design capacity of 12bn cubic metres. Most of the committed buyers are local gas distribution firms and industrial users, with power plants the last remaining users yet to sew up deals. 

 

Petrobras to construct gas pipeline 

 

August 30, 2004.  Next September, the Brazilian state-owned oil & gas company Petrobras may start the construction of the pipeline that will transport natural gas from the Basin of Campos (Rio de Janeiro state) to Campinas (Sao Paulo state). The project, to cost $ 285 million resources, may be completed by the end of 2006. Petrobras is studying a new route for the gas pipeline Nordeste II, between Pilar and Mossoro, besides intending to increase the offer in Minas Gerais, from the current 3.5 million m3 to 8 million m3 by 2010. The company will invest $ 3 billion resources in the construction of gas pipelines until 2010 in order to transport 80 million cubic meters mainly earmarked at the North and Northeast regions. In Dec 2004-Jan 2005, there will be drilled more six oil wells in the North Coast of Brazil, concerning the Basin of Ceara, Barreirinhas, Para-Maranhao and Foz do Amazonas. The North and Northeast regions account for 100,000 barrels per day.

 

Philippines, Iran agree to boost oil trade

 

August 28, 2004. The Philippines and Iran have agreed to strengthen bilateral cooperation in energy and oil sectors, the Philippine government said. The accord was forged during a meeting between President Gloria Macapagal-Arroyo and Iranian Foreign Affairs Minister Kamal Kharrazi who paid a courtesy call at the Philippine presidential palace. During their meeting, Arroyo and Kharrazi explored several areas of bilateral cooperation, notably in energy and agriculture, specifically talking about oil supply, exploration and development of natural gas, and construction of new power plants. Considered the world's second largest producer of oil and natural gas, Iran supplies 60,000 to 70,000 barrels of crude oil per day to the Philippines, representing about 25 percent of the country's fuel requirements.

 

 

Russia and China to consider energy cooperation

 

August 25, 2004. Russian Industry and Energy Minister Viktor Khristenko and Chinese Minister in Charge of State Development Reform Commission Kai Ma will discuss issues of joint cooperation within the framework of a session of the Russian-Chinese sub-commission for energy cooperation held in Beijing on August 24 to 26. According to experts, one of the most important issues of negotiations is construction of an oil pipeline from Eastern Siberia to the Far East. The Chinese Ambassador to Russia has made it clear recently that the talks on laying this oil pipeline will take place during a visit of Chinese State Council Premier Wen Jiabao scheduled for this fall in Moscow. Moreover, an adviser of the Chinese Embassy declared that China was interested in buying YUKOS' subsidiary Yuganskneftegaz.

 

Iran wants foreign investment to help it meet energy targets

 

August 24, 2004. OPEC member Iran called for increased foreign spending in its oil and gas sector, in part blaming underinvestment in energy infrastructure for current record high oil prices. Iran's Deputy Oil Minister Mohammad Hadi Nejad Hosseinian predicted oil prices would stay close to $50 a barrel in the short term as steep world demand and unrest in the Middle East drive prices higher. "Most OPEC producers have been unable to supply extra oil as a result of inadequate investment during the period when oil prices were weak," said Hosseinian. He called for foreign cooperation to help Iran meet a target of producing 5.5 million barrels of oil per day and 700 million cubic meters of gas per day by 2010. Iran currently produces around 4 million barrels per day. Projected investment costs would total $50 billion over the next six years. "Iran expects to rely heavily on foreign investment to implement its ambitious plans," Hosseinian said.

 

China keen to increase gas use, needs foreign investment

 

August 27, 2004. China is keen to boost natural gas consumption to reduce a worrying reliance on dirty coal and costly crude oil, but will need to entice participation from the likes of Royal Dutch/Shell to help defray massive costs.  China, the world's largest oil consumer after the United States, is spending billions of dollars to build pipelines and terminals to try and boost natural gas use to 8 percent of its energy mix by 2010, from a paltry 3 percent. The global average is about 25 percent, much of which goes to households for heating and cooking, or power plants. But the difficulty of snaring foreign cash came to the fore this month after the collapse of a venture with PetroChina Corp. to build a $20-billion West-to-East gas pipeline, which would have counted Shell, Gazprom and ExxonMobil Corp. among its investors.

 

POWER

 

 

ABB to set up new power transformer line in Brazil

 

August 26, 2004. Swiss engineering group ABB plans to expand its operations in Brazil to increase production of power transformers primarily aimed for export to the United States.  ABB's Brazilian unit beat out branches in China, India and other Latin American countries to set up the new production line, which will cost about 19 million reais ($6 million). ABB opted to expand its factory in the southern state of Santa Catarina to enable it to triple production because Brazil offered qualified labor, competitive costs and potential to expand in the domestic market.

 

China to invest $ 24 billion in four hydropower stations

 

August 27, 2004. China is to invest $ 24 billion to build four new hydropower generation stations on the Jinsha River, a main tributary of the Yangtze River.   Their construction is expected to be finished in 2020.  The four stations - Xiluodu, Xiangjiaba, Wudongde and Baihetan - will have a combined installed capacity of 38.5 million kilowatts. Funding details are not revealed but it has been mentioned that it would be derived from electricity revenues at the Three Gorges Project, which is the world's largest power project.  Upon completion, Yunnan province will serve as an important power base to transfer electricity from western China to the fast-growing eastern areas. China is facing a serious electricity crisis as its booming economy has created massive demand for energy that could result in a 30,000 megawatt power shortage over the summer months - the worse shortage since the 1980s.  The tight electricity supply is expected to ease in 2006 as the government boosts spending on power plants to relieve pressure on overloaded grids.

 

China needs to invest $120 billion in power generation

 

August 31, 2004. China needs to invest 120 billion dollars in the next five years to generate 215-245 million kilowatts of power to meet its huge demand and reduce crippling power shortages and to increase power.  That would require an investment of one trillion yuan ($120 billion).  Further investments would be needed, including 750 billion yuan to improve power grids. China would therefore need to look for new financing channels which could mean adjustments in the prices of electricity. China still relies on coal for most of its power and will continue to do so in the near future. Its thermal power plants, most of which are coal-fired, are estimated to generate 477 million to 503 million kilowatts of electricity by 2010, which would require 1.3 billion tons of coal.

 

Pakistan spent Rs 184 trillion on nuclear plan in 32 years

 

August 30, 2004. Pakistan is said to have spent a recurring two percent of its national budget ever since the conception of its nuclear programme in 1972 which is in total an amount of only Rs 184.295 trillion in the last 32 years. A statistical study reveals that India may have spent three times more than Pakistan on its defence and nuclear enrichment programme.

Nigeria spends N 28 billion on new power projects

 

August 30, 2004. A total of Naira 28.659 billion has so far been expended on four new power generating plants located at Geregu - Ajaokuta Kogi State, Papalanto and Omotosho in Ogun State and Delta Power station by the National Electric Power Authority (NEPA). The projects, which were among the series of power re-enforcement initiatives being embarked upon by the Federal Government to enable the authority achieve significant leap in power generating capacity, are expected to come on stream latest by December, 2006. The payments totaling N6 billion were made to Siemens, the engineering company handling the power plant at Geregu in two installments of N4 billion in the first quarter and N2 b in the second quarter. The Geregu plant has a projected capacity of 424 MW and according to contract figures is estimated to gulp N32 billion when completed.  About N5 billion each was paid to the two Chinese firms - SEPCO and CNEC handling the construction of the power stations at Papalanto and Omotosho.

 

Nigeria increases power generation to 3363 MW

 

August 28, 2004. The Nigerian National Electric Power Authority (NEPA) said it has achieved a new power generation level, from 3030 MW to 3363 MW. The increase was as a result of the current stability in gas supply to the thermal power plants as well as the appreciation in water level in the Hydro power generating stations. NEPA last achieved a peak generation of 3479 MW in August, 2003.  The authority presently has the capacity to match that level except for limitations it faces in the transmission network facilities.

 

Thar coal: an alternate fuel resource for Pakistan?

 

August 30, 2004. Pakistan today is in the grip of energy crises because of a shortfall in oil, natural gas and hydrothermal energy productions.  The present situation has been aggravated because of low hydro levels in major rivers and reservoirs and change in the weather cycle. Presently, Pakistan is meeting this energy gap through import of petroleum products worth $3.5 billion annually. This import bill is going to get larger and larger every year unless coal as an alternate resource is developed.  The energy gap is expected to peak around 2010 giving only five years to plan, initiate and execute new projects.  The coal resources of Thar are the only assured resources available which could meet all current and future requirements of thermal power production. The reserves (estimated to contain 175 billion tonnes) at 50 per cent availability and 60 per cent recovery are likely to hold a potential equal 16 billion tonnes oil equivalent. Results of preliminary studies carried out indicate that the deposits can be economically exploited through open cast mining for Thermal power generation.

 

Philippines Transco completes Leyte-Bohol linkup project

 

August 30, 2004. State-run National Transmission Corp.(Transco) reported that it has completed the P 700-million Leyte-Bohol Interconnection Project (LBIP) with the full energization of its Stage 2 component last week. Transco president Alan T. Ortiz said with the project completion, the said transmission lines will now have the capability to transport 100 megawatt (MW) of power from the previous 40MW. He said the Japan Bank for International Cooperation (JBIC)-funded LBIP was designed to provide an additional 260 circuit kilometers of 138kV transmission lines and 130 MVA substation capacity in the power hungry Visayas region. Stage 1, which was completed in February 2001, involved the installation of 138kV submarine cables and overhead transmission lines. For Stage 2, Transco put in place 115 circuit kilometers of 138kV steel tower transmission lines from Ormoc in Northern Leyte to Maasin in Southern Leyte and expanded the capacity of the Ormoc substation, the Maasin substation and the Ubay substation in Northeastern Bohol.

 

 

Ecuador proposes bill to reform power sector

 

August 26, 2004. Ecuadorean President Lucio Gutierrez sent a fast-track bill to Congress that aims to impose order on a chaotic electric sector and lure needed investments in hydroelectric power, a document showed. Gutierrez, whose Patriotic Society political party has just five of Congress' 100 seats, proposed creation of a trust that would receive state electricity distributors' revenues from energy sales and help channel them to power generators. The goal is to put an end to chronic delays in payments by inefficient distribution companies, which have spooked investment in hydroelectric power and left Ecuador dependent on more costly diesel-powered energy. The government proposes to create the trust by issuing up to $500 million in 12-year government bonds. The bill also proposes to crack down on distribution companies that fail to keep up with their costs and impose fines and prison sentences on anyone who tampers with, steals or destroys electricity or other public services.

 

Shanghai to ease curbs on power

 

August 30, 2004. Shanghai said peak summer energy demand has passed and it will end some of the energy-saving measures that disrupted power supplies to factories, including those run by Volkswagen AG and Sony Corp. China's biggest commercial city has rationed electricity to some factories and retailers, and turned off decorative street lights since May, to cope with power demand that's been running ahead of supply. The Shanghai government said that the advent of autumn has cooled demand and the curbs will begin to be eased this week. Shanghai's announcement suggests China's power crisis, this year the worst in decades, passed its peak for this year. That will give the government time to upgrade the nation's power supply system, by building more generators, installing more power lines and unclogging rail coal shipments to power plants.

 

China trying to diversify energy supply

 

August 31, 2004. China is seeking alternate energy supplies in regions where sources other than coal or oil, such as solar or wind power, are possible. The use of solar and wind energy is mature in China but the effective use of terrestrial heat and tidal energy remain primitive. China has formed an energy development strategy that depends on the uniqueness of local energy resources.  In northern China, wind power development has become a popular industry. China has 3.2 billion kilowatts of wind power capacity, 253 million kilowatts are useable, ranking first in the world. In the west, where the average daily sunlight surpasses 3,000 kilowatts, solar power use has been used. In Qinghai province, there are 39 established solar power stations, effectively solving power shortages in remote areas. Meanwhile, China is also developing terrestrial heat and tidal energy, mainly in provinces in southwestern China and provinces along the coast respectively. Experts noted the use of alternative energy resources usually have problems in technologies and funds, with higher development costs and lower utilization rate. 

 

Nigerians to enjoy stable power supply in 2007

 

August 30, 2004. Power generation in Nigeria would be increased to 10,000 mega watts by 2007 which would signal a near end to the frequent power interruption in the country.  The main aim of the target was to close the gap between demand which is presently 6000mw as against supply which is 3000mw, stressing that though the gap was still much, the authority has recorded significant improvement from what used to be the situation in 1999. In 1999, power generation was 1800 MW, giving room to epileptic power supply, frequent black out but now it has increased it to 3000 MW.

 

 

Talisman energy to build offshore wind farm demonstrator project

 

August 26, 2004. Talisman Energy (UK) Limited a wholly owned subsidiary of Talisman Energy Inc., has announced plans to construct a C$58 million (Pounds Sterling 24 million) deepwater wind farm demonstrator project adjacent to the Talisman operated Beatrice Field, 25 kilometres off the east coast of Scotland.  Initially the two turbines will provide electric power for Beatrice and, if successful, Talisman will evaluate a large scale commercial project. The demonstrator project will test technologies for deepwater wind farms distant from the shore, with no visual impact. The results will help determine if large-scale developments of this type are a practical and economic source of renewable energy. The project will include the design, construction, installation and operation of two prototype turbines. The power generated by the turbines will be used at the Beatrice platform and will operate alongside Talisman's existing operations at Beatrice without affecting production. It is anticipated that construction of these turbines will begin later this year and first electricity generation is expected to begin late in 2006. A number of jobs will be created in Scotland and other parts of the UK, mainly in the areas of engineering design, fabrication and operations support.

 

Nicaragua to call for 400MW geothermal bids

 

August 30, 2004. Nicaragua's energy regulator INE will call for international bids on September 16 for two geothermal projects totaling 400MW installed capacity, a project source told BNamericas.  The projects are Hoyo Monte Galán (250MW), which lies 6km from Momotombo, an active volcano in León department, and Managua-Chiltepe (150MW), some 12km from Managua City. Interested companies will have to submit proposals in December and the INE will open proposals on January 6, 2005. INE will announce the winners by March, the source added. In line with Nicaragua's geothermal law, construction would have to begin within six months of signing the contracts. The winning companies will determine in how many phases they wish to implement the projects' total capacities, although INE expects that the first stage of each respective project would likely be some 50MW.

 

Commemorative stamp recognizes Rajiv Gandhi’s support for renewable energies

 

August 25, 2004. India has celebrated the birthday of a former prime minister by issuing a special commemorative stamp on renewable energy. The stamp was issued by the Department of Posts and the Ministry of Non-Conventional Energy Sources to mark the of 60th birth anniversary of Shri Rajiv Gandhi, who served as Prime Minister of India from 1984 to 1989. The current prime minister Manmohan Singh called on the Ministry of Non-Conventional Energy to accelerate development and deployment of frontier technology, adding that diligent efforts are needed to find substitutes for oil. He emphasized the need to provide renewable energy solutions to fulfill the national goal of providing electricity to all rural homes. India has the capability to be a world leader in renewable energy, and Singh credits Gandhi with the vision at least 15 years before the technologies started being deployed in the country.

 

Survey underscores enormous potential for low-energy homes in Europe

 

August 25, 2004. The number of passive and low-energy houses will increase “dramatically” in coming years, according to a survey by the Fraunhofer Institute of Solar Energy Systems. Even in the worst case scenario, the number of passive solar houses will increase from the current annual level of 1,300 to 60,000 units a year by 2010. The market for three-litre houses (homes which require less than 30 kWh of energy year for every m2 of floor space) will increase from 3,500 to 100,000 and, by 2010, half of all new buildings will be passive or low-energy homes. Two market research companies, Freiburger Büro für Solarmarketing and Energieagentur Regio Freiburg, questioned 180 architects, engineers, contractors and manufacturers of prefabricated housing about the development of optimal construction methods.

 

Green heat system to cool downtown Toronto

 

August 25, 2004. One of the world’s largest green heat systems has been commissioned in Canada’s largest city. Enwave’s Deep Lake Water Cooling system can provide cooling for 130 office towers in the downtown core. The system pumps water of 4°C temperature from a depth of 83 m below Lake Ontario, which is used to chill Enwave's cooling plant before it is distributed to customers for air conditioning. The earth energy system is used in cooling mode only, after which it is distributed for potable water consumption throughout the city. The project produces enough air conditioning for 20 million square feet of office space, and initial customers include the Air Canada Centre, Metro Toronto Convention Centre, Royal Bank Plaza, TD Centre and Steam Whistle Brewing. Compared with traditional space cooling, the system reduces electricity use by 75% and will eliminate 40,000 tonnes of CO2, equal to taking 8,000 cars off of the streets. It also frees 59 MW from the Ontario electrical grid.

 

Automobile companies to commercialise fuel cell vehicle plans

 

August 25, 2004. Following a review of strategic alternatives, Ballard Power Systems has entered into a comprehensive non-binding Memorandum of Understanding (MOU) with DaimlerChrysler and Ford Motor Company to realign the partners’ responsibilities and ensure their long-term commitment to advancing fuel cell technology and commercializing fuel cell vehicles. The MOU outlines several initiatives, including further defining the roles and responsibilities of the Vehicular Fuel Cell Alliance partners, and establishing program funding requirements to ensure that the partners continue to build on their leadership. The partners’ roles and responsibilities will be redefined, with Ballard intensifying its focus on its traditional strengths in fuel cell research, development and manufacturing, while continuing to support the development of its electric drive system.

 

BP gets go-ahead for London bus H2 station

 

August 25, 2004. BP has obtained planning permission for a hydrogen refuelling station in London, after Deputy Prime Minister John Prescott overruled planning officers with Havering borough council. The temporary planning permission covers the remaining year of the project, which is expected to run through 2005. BP hopes that the installation can be completed by Christmas. The facility will be built at an existing BP Connect gas station along the A127 road in a residential area of Hornchurch, Essex which already features solar panels on the roof and wind turbines. BP says the site is the only appropriate location for refueling London’s three fuel cell buses, which have been in service (on route 25) between Ilford in Essex and Oxford Circus in central London since January.

 

Nokia demonstrates fuel cell cellular phone

 

August 24, 2004. Finnish-based cell phone giant Nokia is testing wireless cell phone headsets powered by miniaturized direct methanol fuel cells that could offer two or three times the runtime of current portable devices. The fuel-cell earpiece and microphone are still at least a few years away from the marketplace, but the breakthrough indicates one direction the cell phone of the future could take. About 100 Nokia employees are testing the headset, which connects to the cell phone via the Bluetooth short-range wireless technology. The cells are recharged by squirting methanol from a small separate container into a tiny internal tank on the headset; each charge provides about 10 h of talk-time, compared with only about 2 h for current Bluetooth headsets.

 

 

 

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