Energy News Monitor |Volume IV, Issue 37

Peak Oil, the Rise of China and India, and the Global Energy Crisis

The spectacular growth of the Chinese and the Indian economies is transforming the world at an unprecedented pace. Under current trends, it is suggested that China is set to become the world's largest and India the third largest economy by 2020. Some predict that after centuries of Western domination, now it is just a matter of time before Asia recovers its historical leadership over the world economy, with China and India at its centre (Arrighi and Silver, 1999; Arrighi et al., 2003).

The rise of Western industrial capitalism under the British and American hegemony coincided with (and one may say, depended upon) the enormous expansion of energy consumption, especially the consumption of fossil fuels (oil, gas and coal). Today fossil fuels account for 80% of the world's total primary energy supply. However, there is growing consensus that the world's total oil production is likely to reach its peak in the near future and experience an irreversible decline thereafter. Further, the greenhouse gas emissions from human activities (primarily from the use of fossil fuels) contribute to global warming with potentially catastrophic consequences. To prevent or alleviate these, it is necessary to dramatically reduce the use of fossil fuels.

In this context, a serious question may be raised: does the world have enough energy and other resources to accommodate China's and India's search for material abundance, with their enormous population? To the extent that this cannot be accomplished easily, what could be the implications for China and India, and for the rest of the world?

This article discusses the interactions between the economic rise of China and India and the global energy crisis that is likely to take place in the coming half-century. The next section discusses the changing relative positions of China and India in the world economy and the potential implications for world energy consumption. The third section discusses the coming peak of the global oil production, impact of global warming and the prospect of alternative energy sources. The fourth section evaluates the likely prospect of world energy supply in the coming half-century and argues that there will be great difficulty for the world to meet the projected energy demand. The shortage of liquid and gaseous fuels could become a binding constraint on the future world economy. The fifth section discusses the implications of China's and India's economic rise for the global energy crisis. Several possible scenarios are considered. The last section concludes the article.

China and India in the World Economy: History and Future

Until the early nineteenth century, China and India were the two largest economies in the world, accounting for more than one-third of the world GDP. The two countries, however, experienced sustained declines in relative economic positions over the following 150 years. Western Europe dominated the world economy through the nineteenth and early twentieth centuries. After World War II, the USA achieved undisputed world economic hegemony. Since then the US share in the world GDP has declined. Nevertheless, the USA remains the world's largest economy. However, if the current trend continues, China will soon overtake the USA to become the world's largest economy. By 2020, China and India combined will again account for more than one-third of world GDP, restoring their historical positions.

Such a development would certainly lead to major transformations in the world economy and geopolitics. There is one area in which the economic rise of China and India is set to bring about fundamental changes that has not been discussed extensively so far. That is, how would the rise of China and India affect the consumption and distribution of world resources, especially the energy resources?

The current pattern of world energy consumption is highly uneven. The high-income countries, with 18% of the world population, account for 49% of the world's total primary energy consumption and 60% of electricity consumption. China and India together, with 37% of the world's population, account for only 19% of the world's total primary energy consumption and 16% of the electricity consumption. (1)

According to the footprint analysis, the current rate of energy and resources consumption in high-income countries is already unsustainable. It takes 8.5 hectares of productive land to provide food, water and energy settlement area for an average person living in a rich country. Yet the world's productive land per person is about 1.2 hectares (Trainer, 2005: ch. 10). To stabilise the global climate, the world's emissions of greenhouse gases need to fall to about one tonne of carbon dioxide equivalent per person. But the current emissions in high-income countries stand at about 11 tonnes of carbon dioxide equivalent per person (in the USA it is about 20 tonnes per person).

This raises a serious question. How much energy and other resources are left available for the development of the rest of the world? Can the world generate a sufficiently large energy supply in the coming decades to accommodate the rise of China and India?  (2)

Under the current trend, China and India together will account for about one quarter of the world's total primary energy consumption by 2020 (this would still be less than their share of the world population). If the energy consumption in the USA, China and India all grow at their current trends, then by 2050 the total energy consumption in these three countries would reach nine times the US energy consumption in 2004 or 11 times the US energy consumption in 1990 (the reference year for the Kyoto Protocol). Will the world have enough energy resources to support ten more Americas?

There is no doubt that the Chinese and Indian people have every right to development, understood as the fulfillment of their basic needs as well as their desires for a decent life. Further, it would not be unreasonable for one to argue that the existing pattern of resources distribution in the world is historically and morally unjustified. Nevertheless, to the extent that the existing world economy is already on an ecologically unsustainable path, it cannot be denied that the attempt to replicate the existing pattern of consumption of the high-income countries among nearly two-fifths of the world population would make it even less sustainable.

Peak Oil, Global Warming and Limits to Energy Supply

Peak Oil

The current world economy depends on fossil fuels for 80% of its total energy supply. Oil accounts for 34% of the world's total primary energy supply, coal accounts for 25%, natural gas for 21% and nuclear energy for 6.5%. Among the renewable energies, biomass and waste (wood, other biomass, animal products, municipal waste and industrial waste) account for 10.6%. Hydro-electricity accounts for 2.2% and all others (solar, wind, geothermal, tide and wave) for a mere 0.4%.

In terms of the world's total final energy consumption, oil accounts for 42%, gas accounts for 16%, coal accounts for 8%, biomass and waste account for 14% and electricity and others account for 20%. Thus, oil is currently the single most important source of energy, accounting for more than two-fifths of the world's total primary energy supply and two-fifths of the world's total final energy consumption.

According to Campbell (2005a; 2005b), global oil discovery peaked back in the mid-1960s. Since 1980, new discovery has been less than depletion for every year and the gap has tended to grow. Global production of all oil liquids (including conventional oil as well as heavy oil, deep-water oil, polar oil, gas liquids, etc.) is expected to peak around 2010. By 2050, the total oil production is expected to fall by about 70% from the peak level. (3)

Trainer (2006a) counted a total of 61 estimates of the world's total conventional oil resources and concluded that there is a considerable agreement on a figure under two trillion barrels. As the world's total oil production so far has been about one trillion barrels and the peak production is likely to occur when about half of the total oil resource has been depleted, these estimates suggest that the world oil production peak is likely to occur in a few years. (4)

Until recently, governments and businesses have tended to pay little attention to the peak oil argument. However, the idea is now gaining acceptance among mainstream institutions. The International Energy Agency (IEA) recently pointed out that the oil fields on which Europe and the USA have come to depend, including Russia, USA, Mexico and Norway, would peak in the next five to seven years. According to IEA, the world is on a course that will lead it "from crisis to crisis" unless governments act immediately to save energy and invest in nuclear and bio-fuels. IEA calls for a total investment of $US20 trillion in energy infrastructure from now to 2030 to stave off energy crisis (Financial Times, 8 November 2006).

Natural Gas and Coal

Much (although not all) natural gas production is linked closely to oil production. The peak of the world natural gas production is likely to occur not long after the peak of the world oil production. Because of the physical features of natural gas, it has a depletion pattern different from oil. Campbell (2005a: 29-55; 2005b: 210-16) expects the world natural gas production to keep rising until 2025 and then stay on a high plateau before declining sharply after 2045.

Among the fossil fuels, coal is relatively abundant. The world's total identified coal resource is said to be 35 trillion tonnes (Cui, 2006: 16). Much of it, however, may never be recovered due to declining net energy returns (the net energy output that can be produced for each unit of energy input) and environmental constraints (Heinberg, 2003: 129-32). The world's economically recoverable coal is estimated to be about 750 billion tonnes of coal equivalent. At the current rate of production, it is sufficient to last more than 200 years (Boyle et al., 2003: 167). Trainer (2006a) used a high estimate of the world's potentially recoverable coal, at two trillion tonnes of coal equivalent. At the current rate of production, this would be sufficient to last more than 600 years.

However, with economic growth, coal could be depleted much faster. If coal consumption grows at 2% a year, then the world's total recoverable coal would be completely depleted before the end of this century (based on the lower estimate) or by the mid-twenty-second century (based on the higher estimate).

(1) The world energy statistics cited in this article, unless stated otherwise, are from IEA (2006).

(2) Data for the primary energy consumption of the world and selected countries are from World Bank Group (2006). For the post-2004 period, it is assumed that the annual energy consumption of each country grows at the same rate as the average annual growth rate of energy consumption between 1994 and 2004.

(3) For complete discussions of peak oil estimates, see Campbell (2005a; 2005b). For mathematical models that apply the Hubbert's method to the global situation, which correctly predicted peak oil production in the USA, see Korpela (2005). For general discussions of peak oil theories and the critiques, see Heinberg (2003; 2004), Kunstler (2005) and Mobbs (2005). The Association for the Study of Peak Oil and Gas Ireland (ASPO Ireland) publishes monthly newsletters (http://www.peakoil.ie), which provide updated oil and gas production profiles and estimated dates of peak production.

(4) The US Geological Survey (USGS, 2006) put forward a very optimistic but widely cited "mean estimate" of potentially recoverable conventional oil resources at about 3.5 trillion barrels. Campbell (2005c) has criticised the USGS estimate. The December 2006 Newsletter of ASPO Ireland carries an article showing that the actual trajectory of world oil discovery is on a path that would fall below the USGS low estimate of about 2.5 trillion barrels (ASPO, 2006).

 

to be continued…

 

Short-Term Trading of Natural Gas: Some Risks Involved

Ahmed El Hachemi Mazighi, Advisor, Strategy & Prospects, Sonatrach- Commercialisation, Algiers, Algeria

 

Abstract

Traditionally guided by long-term contracts, the international natu­ral gas trade is experiencing new methods of operating, based on the short term and more flexibility. Today, indeed, the existence of uncommitted quantities of natural gas, combined with gas price dis­crepancies among different regions of the world, gives room for the expansion of the spot-trading of gas.

The main objective of this paper is to discuss three fundamental risks related to the short-term trading of natural gas: volume risk, price risk and infrastructure risk. The defenders of globalisation ar­gue that the transition from the long-term to the short-term trading of natural gas is mainly a question of access to gas reserves, de­creasing costs of gas liquefaction, the building of liquefied natural gas (LNG) fleets and regasification facilities and third-party access to the infrastructure. This process needs to be as short as possible, so that the risks related to the transition process will disappear rap­idly. On the other hand, the detractors of globalisation put the em­phasis on the complexity of the gas value chain and on the fact that eliminating long-term contracts increases the risks inherent to the international natural gas business.

In this paper, we try to untangle and assess the risks related to the short-term trading of natural gas. Our main conclusions are list­ed over the page:

1.  the short-term trading of gas is far from riskless;

2. volume risk requires stock-building in both consuming and pro­ducing countries;

3. price risk, through the high volatility for gas, induces an in­crease in options prices; and

4. there is no evidence to suggest that money-lenders’ appe­tite for financing gas infrastructure projects will continue in a short-term trading system, and this would be a threat to con­sumers’ security of supply.

Traditionally guided by long-term contracts, the international natural gas trade is experiencing new methods of trading, based on the short term and more flexibility. Today, indeed, the existence of uncom­mitted quantities of natural gas, combined with gas price discrepancies among different regions of the world, gives room for the expansion of the spot-trading¹of gas. Even if the relative share of this trade is still very small — no more than five per cent of the total international gas trade in 2000, according to Cedigaz statistics (Cedigaz, 2002) — we can expect an increase of it in the next decade, mainly because it offers arbitrage windows for both the client and the producer.

The main objective of this paper is to discuss three fundamental risks related to the short-term trading of natural gas: volume risk, price risk and infrastructure risk. The defenders of globalisation argue that the transition from the long-term to the short-term trading of natural gas is mainly a question of access to gas reserves, de­creasing costs of gas liquefaction, the building of liquefied natural gas (LNG) fleets and regasification facilities and third-party access to the infrastructure. This process needs to be as short as possible (Stern, 2002, 2003), so that the risks related to the tran­sition process will disappear rapidly. On the other hand, the detractors of globalisation put the emphasis on the complexity of the gas value chain and on the fact that elimi­nating long-term contracts increases the risks inherent to the international natural gas business (Banks, 2002, 2003).

In this paper, we try to untangle and assess the risks related to the short-term trading of natural gas.

1. The long-term trading of natural gas

Until now, the international natural gas trade has been guided by long-term “take or pay” (TOP) contracts. In these contracts, the producer and the client agree on a programme of gas deliveries, on the duration of this programme, on the price mecha­nism and on the frequency of renegotiation of prices. Short-term trading includes all transactions in the futures markets, plus spot transactions (Mazighi, 2003b). The first outstanding difference between these two types of trading is that short-term trading is supposed to obey a logic of spatial arbitrages, which is a means of enhancing the integration of the three existing regional gas markets. And the second notable differ­ence is that short-term trading corresponds to a logic of temporal arbitrages, which is a means of developing organised markets and gas-storage facilities. On the whole (Morita, 2003), long-term trading provides security, while short-term trading offers flexibility.

Besides this, the main characteristic of long-term TOP contracts is that we have only two fundamental risks: volume risk and price risk. Table 1 depicts the nature and types of these risks, who is exposed to them and the tools or arrangements used to cover these risks. From this table, it appears clearly that we have only two non-covered risks: A2 and B2. The first one exposes the client, while the second exposes the producer, and that is why TOP contracts correspond to an equilibrium situation.² In this long-term trade, the risk of no access to financing tools creates a threat to investment and to the security of gas supply. As a consequence, the client and the producer are both exposed to this risk. One interesting thing to note is that, to avoid the interruption risk, the pro¬ducer needs to have either non-committed gas in excess or the possibility to buy gas on the spot market from other sources. In both cases, it is necessary for the gas supply to exceed the committed quantities. This principle certainly played an important role in the so-called emergence of an “abundant gas” era (Stern, 2002, 2003).

Table 1: Nature and type of risks for long-term TOP contracts

Nature of risk	Type of risk	Who is ex-posed to them?	Tools or arrangements
A. Volume	A1. Interruption	Producer	The producer buys gas on the short-term market or swaps gas with other producer, in order to meets his commitments
	A2. Committed quantities exceed demand	Client	The client takes the gas or pays for it
B. Price	B1. Oil price used for indexation is very low	Producer	The producer fixes a minimum level for the oil price in the indexation mechanism
	B2. Oil price is below producer expectation	Producer	Takes this risk
C. Regulatory	No access to re-gasification facilities	Producer	The client is committed to take the gas and to open access to the regasification facilities
D. Financial	No access to financing tools	Both	The TOP contract serves as a mortgage (Morita, 2003)

This way of trading necessarily provides security of supply to the client and se¬curity of outlet to the producer, which is another proof that the long-term trading of gas corresponds to an equilibrium and to a logic of security. The building of commercial or strategic stocks does not appear to be a necessity, which means that, paradoxically, the long-term trading of natural gas is less costly than short-term trading.

However, this way of trading gas — which still predominates in the interna¬tional gas trade — has, and continues to receive, several critics. Among the criticisms is the fact that it does not provide enough flexibility, as if flexibility were an end in itself. A second criticism — and certainly the most acerbic — is that this way of trading does not correspond to the logic of free trade, which is supposed to be the op¬timal logic. In reality, the defenders of globalisation overlook the fact that the gas in¬dustry is a network industry, where access to the resource can sometimes be more im¬portant than a price reduction.

Unfortunately, switching from this long-term trading to a pure short-term busi¬ness will expose both the client and the producer to volume and price risks. Moreo¬ver, unless we have a liquid physical market, risks A1 and A2 will require the building of commercial stocks for gas. The price risk will require the emergence of organised markets that offer suitable financial tools, such as futures contracts and options. Ac¬cording to (Mercey, 2003), the financial risk will be more difficult to assess without TOP contracts, lenders’ appetites for new investment will be reduced and, due to regulatory problems, we could even face disinvestment in the gas midstream (transportation).

 On the whole, switching from TOP to short-term trading means changing only the governing principles of the international gas trade. All risks will persist, with large uncertainties and different degrees of exposure.

2. Volume risk

Switching to the short-term trading of natural gas, through the principle of ar­bitrage between places, implies that gas will flow with priority to markets with high prices. Figure 1 depicts the differences in gas spot prices between one of the major United States gas-interconnection systems (Henry Hub) and the main United King­dom gas-clearing system (national balancing point, NBP). If the gas market was global in 2002–03, gas would have flowed to the US market and the price differences would have certainly decreased rapidly, reducing the attractiveness of the US market.

Figure 1: Spot price differences between the US market (Henry Hub) and the UK market (NBP)

Source: data from various issues of World Gas Intelligence.

 

Notes:

1.  In the area of liquefied natural gas (LNG), spot-trading refers to LNG cargoes diverted from their original routes, plus uncommitted LNG sales. In the area of pipeline gas, spot­trading refers to the physical side of futures markets.

2.  Fundamentally, the main reason take or pay contracts correspond to an equilibrium situ-ation is that they result from a negotiation process where both producers and clients max-imise their objective functions.

to be continued…

 

NEWS BRIEF

OIL & GAS

OVL gets nod for investment in Venezuela, Qatar

March 4, 2008. The Union Cabinet approved investments of $458 mn by ONGC Videsh (OVL), the overseas investment arm of Oil and Natural Gas Corporation (ONGC), in exploration projects in Venezuela and Qatar. ONGC Videsh will invest $356 mn to pick up 40 per cent stake in the San Cristobal oilfield in Venezuela. Venezuelan national oil company Petroleos de Venezuela (PDVSA) will own the remaining 60 per cent stake. The investment includes a signing bonus of $174 mn and capital expenditure $182 mn in the project. This is ONGC Videsh’s first investment in the Latin American country, which is the world’s fifth-largest oil exporter. Venezuela is also a member of the Organisation of the Petroleum Exporting Countries (OPEC). The field is currently producing about 24,000 barrels per day, with ultimate recoverable reserves in the project area estimated by a joint team of ONGC Videsh and PDVSA at 232.38 mn barrels that can yield up to 1 lakh barrels of oil per day. The Cabinet also approved ONGC Videsh’s proposal to invest upto $102 mn in Najwad Najem field in Qatar. ONGC Videsh won a stake in the field in March 2005 after it bid for the block in 2004. The Najwat Najem oil structure is located in the Arabian Gulf in offshore Qatar at a distance of about 100 km north-east of Doha. The 120 sq km acreage is located in the eastern offshore in Qatar.

Petrobras to buy 40 pc in ONGC’s gas block

March 3, 2008. ONGC has 100% interest in the Mahanadi deepwater block and has discovered gas for a third time there on December 23 last year. Brazilian oil major Petrobras International Braspetro BV (PIB BV) plans to acquire 40% stake in a Mahanadi deepwater block of ONGC. ONGC has 100% interest in the Mahanadi deepwater block and has discovered gas for a third time there on December 23 last year. The company plans to explore blocks in the basins of Krishna-Godavari, Mahanadi and Cauvery. All these assets are deepwater blocks and have at least one well drilled in each. In turn, ONGC would get stakes in the blocks located in Maranhao, the Sergipe-Alagoas basin and the Santos basin.

Iran, ONGC finalising Gulf field proposal

March 3, 2008. Iran's state offshore company and India's Oil and Natural Gas Corp. have finalised a financial proposal for developing a gas and oil field in the Gulf. The two sides had completed negotiations about the Farsi field in Tehran. ONGC will now begin technical studies of the project, which is planned to take place in two phases with an expected yield of 500 mcf of natural gas per day from each phase. The Farsi block is already operated by ONGC Videsh, the overseas arm of ONGC, along with India's top refiner Indian Oil Corp. Ltd. and smaller explorer Oil India Ltd. Iran is drawing interest from Indian and Chinese firms that are keen to tap the world's second-largest reserves of oil and gas and are less susceptible than many other companies to Western pressure over Tehran's nuclear programme. ONGC and Hinduja Group are also looking at joining the development of Iran's South Pars Phase 12 gas field and the country's Azadegan oil field. 

ONGC to halt work at South Bassein gas field

February 28, 2008. ONGC plans to shutdown the production of its giant South Bassein gas field beginning March 1 for 15 days to operationalise new platform. This will be the second production shutdown in South Bassein since January. The field produces around 12-13 mmscmd of natural gas. Reports added that ONGC is tying up new booster platforms along with its two existing processing platforms BP-A and BP-B to maintain production from this ageing field. While one such new platform was operationalised in January, the other platform would be operationalised in March.

Cairn India to bid for two Lankan oil blocks

February 27, 2008. Cairn India is bidding for two oil exploration blocks in Sri Lanka, namely, blocks 001 and 002 under the ongoing Sri Lankan licensing round. Sri Lanka’s block 001 is spread over 3,338 sq km, and block 002, 3,572 sq km. Block 001 is, in fact, closer to the Cauvery basin, where oil and gas has already been discovered, hence it is attracting bids from other international oil exploration companies as well. The chances of striking oil here are higher as geological features of the blocks are similar.

Oil companies begin selling bonds

March 3, 2008. Oil companies have begun selling some of their holdings of oil bonds to meet their respective liquidity requirements. The oil bonds sales have pushed up the spread between the bonds and Government securities close to 100 basis points. The spreads remained high, notwithstanding the oil bonds sovereign guaranteed status. Oil bonds are securities issued to the petroleum marketing companies in lieu of subsidy payments from the government and are intended to partly offset refinery under recoveries. The high spreads were on account of low interest in oil bonds, or for that matter fertiliser bonds or even bonds issued to the Food Corporation of India. The low interest was largely attributed to the bonds being ineligible for maintenance of the Statutory Liquidity Ratio (SLR). Currently, the outstanding investments with the banking sector in Government securities are about Rs 9.63 lakh crore ($238.42 bn). This translated into an investment-deposit ratio of about 33 per cent. This was well above the statutorily prescribed SLR of 25 per cent that banks are expected to maintain against their deposits. The sale of the bonds by the oil companies were mainly for purchasing foreign exchange requirements to meet payment obligations which have mounted during the last few months after the spike in international oil prices. Currently, the global prices are in excess of $100 a barrel. More oil bonds were expected to be floated soon, on account of the government’s resistance to hiking petroleum prices substantially to compensate refineries. Outstanding oil bonds currently amount to about Rs 62,000 crore ($15.35 bn).

 This year, so far about Rs 11,953 crore (2.95 bn) have been placed. With the increasing under recoveries, oil companies have sought SLR status for the bonds. None of the special securities issued against subsidy payments are likely to be given SLR status. Oil companies’ demand for SLR status was partly driven by illiquidity concerns. The illiquidity in turns leads to a premium that translated into a spread over the sovereign securities of identical maturities. The premiums tend to rise in situations when markets become tight, particularly when the refineries begin sourcing large volumes of foreign currency. The rising illiquidity premia in turn has escalated the costs of raising resources for oil companies. During the last few weeks, a tight liquidity, refinery dollar purchases and a deceleration in capital inflows in the country had led to a severe shortage of dollars. The shortage had prompted exporters to take forward cover, driving forward rupee-dollar exchange rate into a discount. According to the bankers, this situation was likely to continue for some more time as the exporters cancel and rebook their forward receivables, to capitalise on the rupee’s fall against the dollar. Liquidity was likely to remain tight in the coming weeks, in view of the advance tax payments. This in turn was likely to keep the illiquidity premia on the oil bonds at the current levels.

Crude oil, gas output falls due to closure

February 28, 2008. The production of crude oil from the country’s sedimentary basins fell marginally by 0.3 per cent to 2.89 mt in January this year compared with 2.90 mt in January 2007. The output was, however, marginally higher than the 2.88 mt in December.

PRODUCTION SLOWDOWN, ROBUST REFINING
Crude oil output (mt)	2.895	2.881	2.901	(-) 0.3
Gas output (bcm)	2.695	2.85	2.767	(-) 2.5
Refinery output (mt)	13.673	13.054	12.979	5.3
Refinery utilisation (%)	108.4	103.5	106.9

The output of natural gas in January was also down by 2.53 per cent to 2.69 bcm compared with the 2.76 bcm in January 2007. Compared with the 2.85 bcm gas produced in December 2007, the fall in January this year was higher at 5.61 per cent. The decline in crude oil and gas production in January was due to a two-week shutdown of a production platform at Bombay High, the country’s largest oil producing field. In the April-January period of the current financial year, crude oil production was 0.28 per cent higher at 28.46 mt compared with 28.38 mt in the same period of the last financial year. Natural gas production was up by 1.7 per cent to 26.89 bcm from 26.44 bcm in April-January 2006-07. In January this year, the country’s oil refineries processed 13.67 mt crude oil, 5.31 per cent higher than the 12.98 mt in the year-ago month. The rise in refinery production is primarily due to private refiner Essar Oil. The quantity of oil processed at the company’s refinery rose almost 161 per cent in January after the full 10.5 mtpa capacity was commissioned in the later part of the month. The refineries, on an average, utilised 108.4 per cent of their capacity in January 2008, against 106.9 per cent in the year-ago month. In December 2007, the capacity utilisation was 103.5 per cent. In the April-January period of the current financial year, refinery output increased 7.30 per cent to 129.78 mt, compared with 120.94 mt in the same period of the last fiscal. Average refinery capacity utilisation during the period was; however, lower at 104.2 per cent compared with 106.7 per cent in the year-ago period.

	Apr-Jan- 2007-08	Apr-Jan 2006-07	Yr-on-yr % change
Crude oil output (mt)	28.464	28.387	0.3
Gas output (bcm)	26.899	26.448	1.7
Refinery output (mt)	129.779	120.941	7.3
Refinery utilisation (%)	-104.2	106.7

RIL to get gas from PMT fields

February 27, 2008. After protests lodged by Reliance Industries, the petroleum ministry has decided to restore gas supplies to its petrochemical plants from Panna-Mukta-Tapti fields, but other consumers may not get such preferential treatment. The ministry, which had in December 2007 cancelled almost all contracts for sale of gas produced from PMT fields and asked state-run GAIL to sell it to critical power and fertiliser sectors, has decided to restore 3.6 mcm of gas per day to RIL's petrochemical plants. Of the 17 mmscmd gas produced by PMT joint venture of RIL-ONGC-BG, GAIL may get 3 mmscmd for its LPG fractionators and petrochemical units, while Gujarat Gas’ allocation may be curtailed to 2.1 mmscmd from earlier 3.05 mmscmd. Torrent Power and Rajasthan Rajya Vidyut Nigam Ltd, who too had protested against the ministry's decision, would also see restoration of 0.9 and 1.5 mmscmd gas allocation. The rest would be given to power and fertiliser sectors. Small consumers in Gujarat, who had contracted PMT gas supplies from Gujarat Gas, would be the worst hit by the ministry's decision. With curtailment in its supplies, Gujarat Gas would limit supplies to city gas projects in the state.

RIL KG gas pipeline to come alive soon

March 4, 2008. The pipeline, longest in India, to evacuate gas from Reliance Industries (RIL) block in the Krishna-Godavari (KG) basin the so called East-West pipeline linking Kakinada in Andhra Pradesh to Bharuch in Gujarat is set to be commissioned in the next three months. The company has set second week of May as an internal deadline for commissioning the 1,440-km pipeline. The 48-inch diameter East-West Pipeline is the longest in the country and covers Andhra Pradesh, Karnataka, Maharashtra and Gujarat. The pipeline would be tested in three phases, first to start from Bharuch in Gujarat to a section in Maharashtra and then from Maharashtra to Karnataka and in the last leg, up to Kakinada where the pipeline begins. The company was hopeful of starting gas production in the second half of this year and the refinery project was nearing completion ahead of initial schedule of 2008 end. RIL has tied up with the Gujarat State Petronet (GSPL) to transport gas from Bhadbhut in Bharuch to RIL’s refinery and petrochemical complex in Jamnagar. After receiving gas from RIL, GSPL will transport the same using its existing pipeline between Bharuch and Rajkot and through new pipelines laid up to Jamnagar. RIL is also setting up two advanced master control centres at its Nocil facility in Mumbai and at Kakinada to monitor and control the flow of gas through the pipeline using the supervisory control and data acquisition system (SCADA), an optical fibre cable network along the pipeline. RIL is also planning another pipeline, in the next phase, from Kakinada to Chennai, and from there to Bangalore and Mangalore. The East-West project is being implemented by Reliance Gas Transportation Infrastructure (RGTIL). 

Adani-GSPC-Essar plans $3 bn LNG terminal

March 4, 2008. A consortium of energy-to-transport majors, Adani group, Gujarat State Petroleum Corporation (GSPC) and Essar Oil, plans to spend Rs 10,000 crore ($2.48 bn) to build a liquefied natural gas (LNG) regassification terminal at Mundra in Gujarat. The 10 mtpa terminal is likely to come up alongside the Mundra port and facilitate the movement of LNG ships into the terminal. However, analysts say that considering the tight LNG supply across the world, it may be forced to buy LNG from the spot market. Spot LNG is currently trading at $14-16 per mBtu, while long-term LNG contracts range from $4 per mBtu to $8 per mBtu. 2009 would be a good time to seal long-term LNG contracts as there was likely to be spare supply in the global markets then, with a few gas liquefaction plants coming up across the world. The proposed LNG terminal, work on which is expected to begin even before the LNG tie-ups are completed, will be the third LNG regassification terminal in the country. The other two operational terminals are the Petronet LNG-run terminal at Dahej and the Shell India terminal at Hazira, both in Gujarat. In the country of its consumption, the LNG is regassified in other terminals and transported to end consumers through pipelines. 

ICSA eyes $25 mn from oil and gas projects

March 3, 2008. ICSA (India) Limited, a Hyderabad-based embedded software solutions and technology provider, is eyeing a bigger pie of the oil and gas-related infrastructure sector in the country and abroad. It is looking at garnering Rs 100 crore revenues from these projects during the next financial year.  The company is in discussions with four oil and gas companies, both in public and private sectors, in India and Malaysia, for deploying its iCAP (intelligent cathodic protection) solution for the latter’s pipeline projects. ICSA develops technology solutions for power, water, oil and gas sectors to identify transmission and distribution losses and monitor power and oil consumption. It had earlier formed a50:50 joint venture with Oil India Limited to explore opportunities in the oil and gas pipeline projects globally, besides deploying iCAP solutions for its 2,000-km pipeline network spread across Assam, West Bengal and Bihar. The JV had already completed work on the latter’s 50-km network in Assam. The addressable market for aggregate technical and commercial losses control (AT&C) in India is currently pegged at Rs 50,000 crore ($12.37 bn). The 13-year-old company, which has patents for three projects, employs 460, of which 130 are dedicated to R&D. It has earmarked Rs 25 crore ($6.18 mn) for R&D this year, as against Rs 17 crore ($4.2 mn) last year. The company would utilise part of the $46 mn (around Rs 184 crore) that it had raised from global investment bank Goldman Sachs through issuance of FCCBs in 2007, to fund acquisitions.

Gujarat bakers shift to CNG to cut losses

March 3, 2008. Consequent to the rise in prices of petrol and diesel, bakers in the state hiked prices of 400 gm and 800 gm bread by Re 1 and Rs 2 per packet, a few days ago. Though it helped smoothen operations, margins still remained squeezed. Almost 80 per cent of bakers use diesel as fuel, apart from wood and furnace oil. But now players like Super Bread and Popular Bread are gradually shifting to gas, hoping to cut losses. While medium and large bakery units with a capacity of 10 tonne bread per day and above have to spend between Rs 10 lakh and Rs 15 lakh, small bakery units have to shell out Rs 5 lakh to modify production facilities to suit CNG. Further, CNG prices too rose by Rs 3.30 per scmd recently and only.  Units with access to gas pipelines can shift while others will have to continue using diesel.

Mahanagar Gas trims price of CNG

March 3, 2008. In the budget 2008-09, the excise duty has been reduced by 2% from 16% to 14%, hence Mahanagar Gas Ltd. (MGL) has decreased the prices of CNG from the midnight of February 29 / March 1, with a view to pass on this benefit to its customers. The effective prices of Compressed Natural Gas (CNG) with effect from midnight of February 29/ March 1,  2008 will be as follows:

Area	Previous price (Rs./kg)	Revised Price (Rs./kg)
Mumbai	22.06	21.70
Thane	22.51	22.14
Mira Road-Bhayander	22.18	21.82
Navi Mumbai	22.60	22.23

This reduction in prices will benefit over 1.8 lakh CNG users including over 1.25 lakh autorickshaws and nearly 60,000 taxis, buses and other vehicles across Mumbai, Thane, Mira Road and Navi Mumbai.

ADB may sell its Petronet stake to L N Mittal

February 27, 2008. Asian Development Bank (ADB) is likely to exit Petronet LNG Ltd by selling its 5.2 per cent holding in the country’s biggest liquefied natural gas importer possibly to promoters or billionaire Lakshmi Mittal. ADB and German Development Bank KfW had recently approved a loan of $169 mn to Petronet for its expansion projects at Dahej and a new terminal at Kochi. However, ADB’s internal norms prohibit it from having both debt and equity exposure in a company. ADB norms also stipulate that it must divest its equity holding in a company three years from the date of the company going public. Petronet had an initial public share sale in 2004 and ADB was to exit Petronet in 2007, but it was persuaded to stay on for a year. The four state-run companies that each hold about 12.5 per cent stake and their French partner GdF which has 10 per cent, have the first right of refusal on ADB’s stake. GAIL and IOC, it appears, are keen to pick up ADB stake, but they may not be allowed to do so by the petroleum ministry. GAIL, IOC, BPCL and ONGC together hold a little less than 50 per cent in Petronet, which is why it is still not a public sector unit. If the promoters were to pick up even half of ADB’s 5.2 per cent, and the remaining is taken by GdF, the company would become a public sector company, and that’s something the petroleum ministry does not want. Although the petroleum secretary is chairman of Petronet and the company enjoys state patronage, it has not been subject to the scrutiny that PSUs come under. Petronet is expanding its Dahej terminal from 6.5 million tonnes to 10 million tonnes and constructing a 5 million tonne a year new LNG import terminal at Kochi, Kerala, by 2011. 

Deora calls for enhanced bilateral ties with Romania

March 4, 2008. The Minister of Petroleum and Natural Gas Murli Deora has called for enhanced bilateral cooperation between India and Romania. Deora emphasized the need for identifying new opportunities, tapping and utilizing potential for mutual benefit in oil & gas sector. According to him, companies of two countries should collaborate in exploration not only in India but also in third countries. Deora offered to share Indian expertise and experience in revamping and modernizing refineries. Deora also informed that a research project is on the anvil which will facilitate combined work by two sides for geological studies of the Himalayan belt. This will open a new vista for cooperation in the Indian sub-continent. Referring to the rich history of long standing friendly relations between India and Romania, Deora acknowledged valuable contribution of Romania in the development of oil and gas sector.

Romania supplied first oil rig to India in March, 1956 along with many other drilling rigs and work-over rigs in our early days of oil and gas development, some of which are still operational. Romania has been involved in major Indian projects such as the thermal power plant at Singareni, the Mangalore pelletizing plant, the Durgapur agglomeration plant and the Hyderabad tractor plant. The high GDP growth rate and vast natural resources of India makes it a priority country for Romania in Asia.

Govt. ends 7-year tax benefit for gas finds

March 4, 2008. Developers of gas fields like Reliance Industries, ONGC and Cairn India may not get the seven-year tax holiday under Section 80-IB of the Income Tax Act, 1961. According to Finance Bill, 2008, the term mineral oil does not include petroleum gas. Many oil and gas producing companies have taken advantage of the scheme. After the ministry realised that gas has become a big money-spinner for a number of companies, the ministry thought about issuing a clarification that mineral oil does not include gas. As a consequence of the clarification that mineral oil for the purposes of Section 80-IB(9) does not include gas, Reliance Industries will not get the seven-year tax holiday it is counting on for its biggest gas find at D6 block in the Krishna-Godavari basin and other areas. The production-sharing contracts signed by the operators of oil and gas fields with the government under the New Exploration and Licensing Policy (NELP) give a tax holiday to all production of oil or gas for seven years from the day of the start of production.

Naphtha duty is back to haunt HPL

March 2, 2008. Haldia Petrochemicals Ltd, (HPL) a three-way venture in which the West Bengal government is a major partner, has been given a body-blow by Union finance minister P Chidambaram’s decision to re-impose an import duty of 5% on naphtha, the raw material from which HPL makes polymers. Two years ago, the duty on naphtha was brought down to zero from 5%, together with the duty on polymer imports, which was reduced to 5%. With the latest change, there is no duty differential between raw material and product. Since April 2007, naphtha prices have increased by 36% and are now at a historically high. HPL is the only petrochemical unit in India that has to import naphtha, since the other petrochemical producers either use natural gas or make their own naphtha. For 2006-07, HPL reported a profit before tax of around Rs 500 crore ($124.93 mn) on a turnover of Rs 8,300 crore ($2.07 bn).

HPL consumes the entire naphtha production of the Haldia refinery of government-owned Indian Oil Corp and imports around 60-70% from West Asia. But, because of the import-price parity formula, HPL will have to pay the higher cost on its entire naphtha consumption, whether imported or domestically-produced. HPL consumes around 1.70 to 1.75 million tonne of naphtha a year. The steady increase in crude petroleum prices over the past year has already added 36% to the global price of naphtha, and the re-imposition of duty on naphtha will be a crippling blow.

Oil’s not well, yet steady

March 1, 2008. The budget plays it safe when it comes to oil. Impact on revenues is seen as neutral to positive. The finance minister has abolished the ad valorem component in excise duty on petrol and diesel. However, the current specific excise duty component, Rs 13.26 a litre on petrol and Rs 3.32 a litre on diesel, will increase to Rs 14.61 a litre for petrol and Rs 4.67 a litre on diesel. Customs duty on naphtha has been increased to 5 per cent from zero, and the central sales tax on goods has been reduced, which includes all petroleum products, to 2 per cent from 3 per cent.

The minister has introduced greater transparency in accounting for oil bonds by including the bonds issued so far in 2007-08 in the Budget highlight. To help oil companies face the adverse impact of the high price of crude, the government had increased prices of petrol by Rs 2 per litre and diesel by Re 1 per litre on February 14. That would help the three government-owned oil marketing companies shave off Rs 840 crore ($209.89 mn) from the projected Rs 71,800 crore ($17.94 bn) retail losses this financial year. Taxes comprise 52 per cent of the cost of petrol and 32 per cent of that of diesel in Delhi. 

Specific duties proposed on unbranded petrol, diesel

February 29, 2008. The Budget proposal to adopt a pure specific excise duty on unbranded auto fuels, petrol and diesel, would mean that the Finance Ministry will no longer reap tax windfall from future increase in prices of these products. The proposal to convert ad valorem plus specific rate on unbranded petrol and diesel to pure specific rate would also check the cascading effect of duties in the event of a future price rise on the oil retailers. Henceforth, there will be only a specific duty of Rs 14.35 per litre on unbranded petrol and Rs 4.60 per litre on unbranded diesel. There will be no impact on retail prices. However, the branded fuels such as Extra Premium, Speed and Power will continue to attract the present ad valorem-cum specific rates. Another proposal that is expected to help the sector is reduction in customs duty on project imports from 7.5 per cent to 5 per cent. This would help reduce the project cost for new refineries, pipelines and oil and gas fields development.

Duty on MS/HSD sold without brand names
Description	From	To
	(ad valorem+specific rate)	(pure specific rate)
Motor spirit	6%+Rs 13/l	Rs 14.35/l
HSD	6%+Rs 3.25/l	Rs 4.60/l

 

Privatise old oil fields to accelerate exploration: ES

February 28, 2008. With international crude prices flirting at over the $100 a barrel mark, the need to reduce incremental import dependence of the country’s energy requirements entails a number of measures including acceleration of oil and gas exploration. To meet this requirement and reduce import dependence, the Economic Survey 2007-08 (ES) has suggested privatisation of old oil fields for application of improved/enhanced oil recovery techniques.

India imports about 72 per cent of its crude oil requirement to service the domestic demand for petroleum products, and international oil prices play an important role in domestic pricing. While production from old fields is a concern, since operationalisation of the New Exploration Licensing Policy (NELP) since 1999, 46 oil and gas discoveries have been made by private/joint venture companies in 13 blocks, which have added more than 600 mt of oil equivalent hydrocarbon reserves. As on April 1, 2007, the investment made by Indian and foreign companies in NELP blocks was $3.887 bn, out of which 30 per cent was by the national oil companies, 61.1 per cent by the Indian private companies and the remaining 8.9 per cent by foreign companies. At present, after concluding six rounds of NELP, 162 production sharing contracts have been signed and area under exploration has increased four times, which covers 44 per cent of the Indian sedimentary basin. According to the Survey, the international price of crude oil and petroleum products has increased phenomenally in recent months.

Customs duty on crude reduced to 2 pc

February 29, 2008. The Government has reduced the customs duty on crude and unrefined sulphur from five per cent to two per cent. The customs duty has been reduced in order to support the domestic fertiliser production. As per estimates, the price of sulphur in the international market in the last one year has gone up from $80 per tonne to around $529 per tonne. The Finance Minister has also proposed the withdrawal of the duty exemption on naphtha for use in the manufacture of polymers, subject to the normal rate of five per cent. However, the naphtha imported for the production of fertilisers will continue to be exempted from import duty.

Govt. may introduce advance pricing rules

February 28, 2008. Rules for advance pricing arrangements are likely to be introduced in India with an eye on reducing transfer pricing litigation between corporations and tax authorities. An announcement to this effect is expected either in Budget 2008-09 or in the direct tax code that is likely to be introduced later. Transfer pricing legislation was introduced in India in 2001 and has emerged as the single biggest source of courtroom battles between Indian tax authorities and companies, a large number of which are multinationals with operations in India.

Tax specialists and industry have been demanding clear-cut advance pricing mechanisms that will allow them to determine the valuation of related party transactions. However, moves to come out with advance pricing arrangements have not been spelt out so far principally because of a lack of experience of such transactions in the official tax administration. Indian income tax authorities have done transfer pricing audits of a number of cases with substantial adjustments, many of which are pending in tribunals or courts.

To implement this arrangement, the government will have to create a statutory framework that would include the process of filing applications for such cases, pre-filing conferences, evaluation and negotiations with tax officials and drafting of the arrangement. An advance pricing arrangement will provide tax payers an opportunity to reach an early agreement with tax authorities on the future application of the arm’s-length principle in their international transactions with related parties.

 The agreement means that the tax administration provides a commitment not to make any adjustment to the transfer price so long as the tax payers stick to the principles agreed in the arrangement. Most developed countries have provided an alternative dispute resolution forum for settling transfer pricing issues amicably as the normal appellate process proves to be quite lengthy. An advance pricing arrangement settles the transfer pricing methodology and the range of profit margins to be adopted for an agreed number of years. The arrangement will be reflected in the return of income of the tax payer, which will not be disturbed as long as tax payer sticks to the principle agreed upon. 

OMCs directed to address complaints regarding LPG supply in WB

February 27, 2008. The Minister for Petroleum and Natural Gas Murli Deora has directed Oil Marketing Companies (OMCs), IOC, BPCL, HPCL to urgently take remedial steps regarding complaints of hardships faced by domestic LPG consumers in West Bengal (WB). According to the the Minister additional imports have been tied up by the oil companies besides operating LPG bottling plants during extra hours and holidays.

Industry expects declared good status for ethanol

February 27, 2008. Expectations among the industry stakeholders that the Government may classify ethanol as a declared good which would give the ethanol-blended petrol programme (EBP) an impetus are running high. Grant of declared good status would ensure a uniform levy on the product across the country. Demand for declared good status for ethanol is being sought by the Petroleum Ministry which has been supported by other stakeholders. The Government may also consider reduction in the current 16 per cent Central excise duty on ethanol for the programme. The Prime Minister’s Office has also written to the State Governments to remove levy of taxes/fees and barriers for implementation of the programme and enable unrestricted movement of the product within the country. In 2006, the Petroleum Ministry had directed that subject to commercial viability, the oil marketing companies would sell five per cent ethanol-blended petrol as per Bureau of Indian Standards specifications. Duty rationalisation is also needed to have price parity between imported ethanol and domestically-procured ethanol. The landed cost of ethanol at Indian ports is about Rs 21 per litre, while the domestic price of ethanol as per the present tender at oil company depot is on an average Rs 28 a litre. Besides the 16 per cent Central excise duty, sales tax rates varies from State to State. The States also levy various surcharges, export fee (from one state to another), import fee, permit fee, licence fee, administration fee, and State excise.

POWER

SJVN bags hydro power project in Nepal

March 3, 2008. State-run Satluj Jal Vidyut Nigam has bagged a contract to develop a 402-MW hydro power project in Nepal. The development comes within two months of GMR Group winning a contract to set up 300-MW Upper Karnali project in Nepal. SJVN agreed to offer 21.9 per cent (about 88 MW) free electricity from Arun-III project. It will also have to give a guarantee of Rs 5 lakh a unit for obtaining a power generating licence, besides Rs 1 lakh per unit for a survey licence. The company would develop the project in five years and operate it for 30 years on build-own-operate-transfer basis. It would also have to lay transmission lines for evacuating power from the project.

 SJVN had earlier offered 4.5 per cent free electricity from Arun-III. However, it raised the quantity to 21.9 per cent after the Nepal government made free power as the main criteria for awarding the projects. In all, nine Companies including GMR Energy, Jindal Steel and Power, Reliance Energy and JP Associates were believed to be in the fray for Arun III. However, GMR did not qualify for the project as the government decided that one bidder would get only one power project.

NTPC to form JV for new power plant

March 3, 2008. NTPC Ltd plans to invest around Rs734.1 mn in setting up a 1,320 MW power plant in the northern Indian state of Bihar. The company also plans to set up a power plant with a similar capacity in a joint venture with a utility owned by the neighbouring state of Uttar Pradesh.

Navyug Engg to invest $470 mn in Astharanga port

March 3, 2008. Hyderabad-based Navyug Engineering Company Limited plans to invest Rs 1,900 crore ($470.41 mn) in the first phase for setting up of an all-weather port at Astharanga in the mouth of Devi river in Puri district of Orissa. It has proposed to invest Rs 1,500 crore ($371.37 mn) for the port and Rs 400 crore ($99 mn) for railway connectivity. The proposed port at Astharanga will have a cargo handling capacity of 20 mtpa in the first phase. The company will sign a memorandum of understanding (MoU) with the Orissa government soon. The state law department had given its concurrence and the approval of the finance department was awaited. The port will be utilised for exporting the finished products from Orissa, supply of coal from Talcher to the south India based steel and power plants, aluminium, alumina, ferro alloys, auto-spares. The first phase of the port was expected to be commissioned by 2011. The Centre was targeting a port capacity of 2 bt by 2016 from 780 mt at present.

Essar plans to invest $12 bn in Gujarat

March 3, 2008. The Essar group has chalked out plans to invest Rs 50,000 crore ($12.37 bn) over the next three years in Gujarat. Essar is planning to set up two 1200 MW power project with Rs 8,000-10,000 crore ($1.98 – 2.47 bn) investment. Besides, the company is aiming to enhance its steel capacity from 4.6 mtpa to 9 mtpa in Gujarat. Essar is enhancing its overall power generation capacity to 6,000 MW for an investment of $5 bn. 

NTPC inks pact with UP for 1 GW power plant

February 28, 2008. State-run power producer NTPC has formed a joint venture with the Uttar Pradesh Rajya Vidyut Utpadan Nigam to build a 1,320 MW thermal power plant near Allahabad. The agreement for the super critical thermal power project is the first such joint venture between the two. The project cost has been estimated around Rs 7,200 crore  ($1.8 bn) . Two units of 650 mw each would have a 50:50 partnership between the two parties and added that a separate joint venture company would be constituted soon. The project would be completed within its stipulated time of 4 years. While 75% of the power generated from the project would go to Uttar Pradesh, the management of the company would remain with the NTPC. Apart from this project, a few other joint venture projects between the NTPC and the UP Utpadan Nigam are to come up shortly. These are the 4,000 MW plant at Lalitpur, a 800x2 Obhra extension project and the 1,000 MW Anpara D project.

Govt. keen on allowing private players in nuclear power

February 28, 2008. Even as the fate of the Indo-US civil nuclear deal hangs in the balance, the Government has favoured permitting private sector investments into nuclear power generation. Allowing private corporate investments in the field of nuclear power has been listed out under the key policy reform measures in the Economic Survey. Private investment in nuclear power should be subject to regulation by the Atomic Energy Regulatory Board and Atomic Energy Commission. Tata Power, Larsen & Toubro, Reliance Energy, GMR, Essar Power and the Vedanta Group are among those in the fray for entering nuclear generation. Participation of private players in nuclear generation is, however, subject to the Government amending the Atomic Energy Act, under which currently participation in the sector is limited to Nuclear Power Corporation India Ltd and sister concern Bharathiya Nabhikiya Vidyut Nigam Ltd. It also stressed on the need to fully exploiting the nuclear and hydro potential for power generation. Expressing concern over the constant slippages in capacity addition targets and mounting subsidy burden, it has stressed on improving financial viability of power utilities, particularly in States, to overcome the crisis. According to revised estimates, the gross subsidies for the power sector would grow to Rs 43,132.6 crore ($10.81 bn) for 2007-08 against the provisional figures of Rs 40,054 crore ($10.04 bn) for 2006-07. The amount could rise to Rs 46,087 crore ($11.55 bn) in 2008-09. Terming the sector as a laggard, the document has noted that the country may add 10 per cent less power capacity than the targeted 12,039 MW during the current fiscal. During April-November, the generation loss due to gas supply shortages was 21.79 billion units. The power sector needed 65.69 mmscmd of gas but only received 36.31 mmscmd. In 2006-07, the generation loss due to low gas supplies was 26.33 billion units.

Cosmos to build hydroelectric plant in Himachal

February 27, 2008. The Delhi-based company will build the 17 MW Chanju-II hydroelectric project in a remote mountainous region in Chamba district, around 450 km from here. The plant will be built on Chanju river, a tributary of the Ravi. The project has been allotted to CHPL for 40 years on build, own, operate and transfer basis. It would cost around Rs. 100 crore ($25.13 mn) to build the Chanju hydro project and will generate 85 mn units of electricity in a dependable year.

Alstom India bags two export orders

February 27, 2008. Alstom Projects India Ltd has won two export orders worth Rs 242 crore ($60.8 mn) for Fujairah Independent Water and Power Plant at Fujairah, UAE, and a hydro order worth Rs 350 crore  ($87.96 mn) for Bujagali Hydroelectric Power Station at Jinja, Uganda, respectively. The heat recovery steam generator (HRSG) order is for Fujairah Independent Water and Power Plant, one of the world's largest desalination plants located at Quidfa in Fujairah, UAE. The order comprises design engineering, supply and delivery of five HRSGs for GT26 at Fujairah site. The hydro order for 5x51 MW (Kaplan machine) is for Bujagali Hydroelectric Power Station at Jinja, Uganda. The main contract was awarded by Salini to Alstom Group out of which Alstom Projects India Ltd will be executing the orders worth Rs 350 crore ($87.96 mn).

BGR Energy bags $199 mn contract in AP

February 27, 2008. BGR Energy Systems, a supplier of systems and equipment for power, oil and gas industries, has bagged a Rs 793-crore ($199.29 mn) order from Andhra Pradesh Power Generation Corporation. The order is for  manufacture, erection and commissioning of auxiliary equipment. This fourth such contract for the company would be executed within 26 months and would also include civil works for the 500-MW Kothagudem Stage VI, a power plant of Kothagudem Thermal Power Station Stage VI.

UHBVN to buy power from BPCL

March 3, 2008. Uttar Haryana Bijli Vitran Nigam (UHBVN) signed an agreement with Bhoruka Power Corporation Limited (BPCL) to purchase energy for next 35 years. BPCL is setting up a project at Western Yamuna Canal, Dadupur (Yamuna Nagar) where a 4.5 meter natural fall is available. Four units of 1.5 MW each would be functional by September 2009. The upcoming project is environment-friendly with all recommended parameters. This is the first effort made by the UHBVN to explore availability of electricity from such a renewable energy project. UHBVN, as per the Haryana Electricity Regulatory Commission (HERC) approved PPA, would purchase electricity at Rs 2.80 per unit from the date of commissioning for 12 years and at Rs 1.70 per unit for the next three years. It is expected that the electricity would be cheaper after 15 years. The net exportable energy would be 29.67 million units per year. The electricity supply would be taken at 33 KV switching substation by which the nigam would be saving Rs 80 lakh per year on account of wheeling charges besides getting clean energy for distribution to consumers at an economical cost. As per order of HERC, the state is to procure up to 3 per cent of total consumption of electricity during the year 2008-09 from the renewable and non-conventional energy sources. 

Govt proposed to create a fund for T& D reform

February 29, 2008. The Government has approved the continuation of the Rajiv Gandhi Grameen Vidyutikaran Yojana during the Eleventh Plan period with a capital subsidy of Rs. 28,000 crore. An allocation of Rs. 5,500 crore is proposed for the Yojana (including NER) in 2008-09. An allocation of Rs. 800 crore has been provided for the Accelerated Power Development and Reforms Project. The poor state of transmission and distribution (T&D) so far has been a drag on the sector. Huge investments are required to be made in T&D, but linked to fundamental reforms. Hence, it has been proposed to create a national fund for transmission and distribution reform. The details of the scheme will be worked out and announced very soon.

Mahindra Forgings inks pact with Wardha Power

February 29, 2008. The company has entered into a Power Delivery Agreement with Wardha Power Company Ltd (WPCPL) for availing the supply of 5 MW power under the Group Captive Concept to the Company's Chakan Plant at an investment of Rs 32.5 mn. WPCPL is expected to commission the project and start supplying power from December 2009 onwards. The Agreement will be valid for 25 years.

TCS in power exchange alliance

February 28, 2008. Tata Consultancy Services (TCS) and three power PSUs, NTPC, Power Finance Corporation (PFC) and National Hydro-electric Power Corporation (NHPC) have teamed up to set up a power exchange. The Companies are in broad agreement for a joint venture, and are thrashing out the details. All these promoters are exploring options for the JV formation. It can be equal equity contribution by each or TCS providing technological solutions and also holding a stake in the power exchange. The exchange will transact power for the short-term, long-term and round-the-clock (RTC) initially and later include hourly trades. The power PSUs and TCS are expected to sign the agreement very soon. This would be the third power exchange in the country. Already, the MCX-promoted Indian Energy Exchange has indicated that it may start operations before March 31. Recently, NTPC and National Commodity and Derivatives Exchange (NCDEX) failed to arrive at an agreement on management control, and thereafter NCDEX and NSE have agreed to float a power exchange, Power Exchange India Limited. The formation of three exchanges would be a boon for electricity consumers, as they would have a variety of choices for drawing power. This would, however, be possible only if the open access becomes a reality in its true sense. Going by the Central Electricity Regulatory Commission data, nine power traders are there in the absence of a power exchange.

Crompton to energise Nagpur power supply

February 28, 2008. Electrical equipment manufacturer Crompton Greaves is working on a business plan to improve the performance of three power distribution divisions in Nagpur bagged from the Maharashtra State Electricity Distribution Company in September 2007.  As per the company, attempts are being made to bring down the transmission and distribution losses, currently at 45 per cent, over the next few years. It is understood that the company has only recently been able to overcome the legal challenges to its foray into power distribution from local associations in Nagpur.

120 power projects under implementation

March 4, 2008. According to the Union Minister for Power, Sushilkumar Shinde, as on December 1, 2007, around 120 power generation projects aggregating to 66862 MW were under construction. According to information available with the Central Electricity Authority (CEA), an estimated expenditure of about Rs937bn has been incurred on these projects. The anticipated requirement to complete the projects is approximately Rs1878bn. Out of the projects under construction as on December 1, 24 thermal, 30 hydro and 4 nuclear power projects have reported some delays.

Power Projects Under Execution

	Central		State		Private		Total
	No.	MW	No.	MW	No.	MW	No.	MW
Hydro	17	8134	16	2527	11	3991	44	14652
Thermal	19	17940	33	12688	20	18422	72	49050
Nuclear	4	3160	0	0	0	0	4	3160
Total	40	29234	49	15215	31	22413	120	66862

Maharashtra to face peak shortage of 3.5 GW by FY12

March 4, 2008. Projects with estimated generation capacity of 5690 MW are likely to fall in Maharashtra during the 11th plan. The energy requirement in Maharashtra is likely to be met in full, but the state is likely to face peak shortage of 3532 MW (16.1%) at the end of 11th Plan (2011-12), according to the anticipated power supply position worked out by the Central Electricity Authority (CEA). During the period April-January 2007-08, the energy shortage in Maharashtra was 16,289 MU (17.2%) and the peak shortage was 4844 MW (26.4%). The energy and peak shortage in Maharashtra during the current year (April-January 2007-08) have reduced marginally to 17.2% and 26.4%, respectively from 17.4% and 26.7% during the same period of last year. Projects with estimated generation capacity of 5690 MW are likely to fall in the state of Maharashtra during the plan period. During the first 10 months of the current fiscal year, the consumption of electricity in Maharashtra was 78,277 MU. According to the projections in the 17th Electric Power Survey report prepared by CEA, an electrical energy requirement for the state has been assessed at 113,878 MU for the next year. The availability of power for Maharashtra, based on the proposed generation target for the year 2008-09 is expected to be 62194 MU from its own generation and 25218 MU from the Central generating stations. According the 2001 Census, there are 41,095 inhabited villages in Maharashtra. Out of this, 36077 (87.8%) have been electrified by the end of December 2007.

Orissa to get half-share from Machkund project

March 3, 2008. After a five-decade-long battle, Orissa succeeded in getting the consent of Andhra Pradesh for acquiring 50 per cent share from Machkund hydro- electric project. At present, Orissa gets 30 per cent share from Machkund project and now the state would get the rest 20 per cent following the consent given by Andhra Pradesh. The payment for the remaining 20 per cent share would be decided by the Central Electricity Authority (CEA), and both the states would file petition for this before the CEA, whose decision would be binding upon them. The Machkund hydro electric project would be expanded and renovated and its cost would be equally borne by both the states. The generated energy would be shared equally.

Environmental clearance to 168 power projects

March 1, 2008. A total of 168 power projects have been accorded environmental clearance during the last three years. This includes 128 thermal power projects, 39 hydroelectric projects and 1 nuclear power project. As on February 15, 2008, 43 power projects are pending for environmental clearance, which include 37 thermal power projects, 5 hydroelectric projects and 1 nuclear power project. To facilitate early decision on these projects, their status is monitored continuously. Environment Impact Assessment (EIA) Notification, 2006 provides for appraisal of the impact that a project will have on the environment. This is done through EIA reports submitted by the project proponents and assessed by the multi-disciplinary Expert Appraisal Committees constituted by the Ministry of Environment & Forests for the purpose.

Coal watchdog on the anvil

February 29, 2008. The Government has proposed to appoint a regulator to streamline the coal sector. A new coal distribution policy was notified in October 2007. 53 coal blocks with reserves of 13,842 mt have been allotted during April-January 2007-08 to Government and private sector companies. The Planning Commission had earlier pitched for having in place a coal sector regulator to approve periodic price revisions of the fuel feedstock, recommend steps for fixing coal prices and regulate trading margins while ensuring e-auctions free of price distortions.

MoU signed for Chanju-II hydro power project

February 29, 2008. Cosmos Hydro Power Limited (CHPL), an independent power producer company (IPP), signed a memorandum of understanding (MoU) with the government of Himachal Pradesh for implementation of the 17 MW Chanju-II hydro-electric project in Chamba district of Himachal Pradesh. As per the MoU signed, the project has been allotted to the IPP for 40 years on build, own, operate and transfer (BOOT) basis. The project, with an estimated cost of about Rs 100 crore ($25 mn), would generate 85 million unites energy in a 90 % dependable year. As a first step, the company would prepare and submit a detailed project report (DPR) to the government within the specified period of 18 months in accordance with the terms and conditions of the MoU signed. The company would be supplying 12 % of the generated power during the first 12 years, 18 % during the next 18 years and 30 % thereafter, free of cost to the state government as royalty.

J&K to revive hydel project as heritage site

February 27, 2008. Asia’s second-oldest hydel power project, over the Jhelum river near Uri in Kashmir, is being revived by the Jammu & Kashmir government. Situated on the historic Jhelum Valley Road, connecting Srinagar with Muzzaffarabad (PoK), this 9 MW hydel power project was constructed in 1905 by European engineers. Commonly known as Mohura hydel power project, it is situated just a few kilometres from the 480 MW Uri hydel power project. The power house of the project is lying defunct. With the objective to promote tourism and protect it as a heritage site, the government is contemplating to prepare a fresh detailed project report (DPR) and handing over the project to a private company by inviting global tenders.

TNEB will buy power from North

February 27, 2008. The Tamil Nadu Electricity Board will buy power from northern States to manage the anticipated power shortage during summer. The State Government also plans to discuss with industries on ways to manage demand by staggering the weekly holidays. Between March and May, TNEB would buy power from West Bengal, Orissa and Assam. The State grid will receive over 250 MW in the first week of March and this would increase to over 400 MW in April. The peak summer demand in the State is expected to go up by about 500 MW from the present demand of about 8,900 MW. In May, the power availability would improve when the wind farms start generating power, Tamil Nadu has over 2,100 MW of installed capacity in wind farms. The generation capacity now available with TNEB is about 8,600 MW and the shortage of about 300 MW is being managed through one hour of load shedding in the rural areas. The State would be divided into six zones and the units in each zone would have the weekly holiday on different days. With the increase in coal prices industrial units are shutting down coal-based power.

OIL & GAS

Essar awarded Vietnamese offshore block

March 4, 2008. Essar Exploration & Production Limited (EEPL), Mauritius, has been awarded an offshore block in Vietnam's prolific Song Hong basin. The block, which covers approximately 5,925 square kilometers, was awarded under a recent licensing round where seven offshore blocks were on offer. It is a shallow water block with average water depth of 60 to 70 meters. The exploration phase is estimated to last five years and the investment for this program will be approximately US$ 60 mn.

Afren signs PSCs for Nigeria gas projects

March 3, 2008. Afren PLC has signed production sharing contracts with Global Energy Co Ltd for its two gas projects in Nigeria. The PSCs cover the OPL 917 and OPL 907 licenses, located in the Anambra Basin, the second most prospective basin in Nigeria with estimated remaining gas resources of over of 5 tcf of gas. A signature bonus of $1.6 mln for each license has been paid by the license participants. The 50-50 joint venture partnership, called Afren Global Energy Resources, will hold a 41 pct stake in OPL 907 and a 42 pct interest in OPL 917 and will be the operator of both projects. The near-term programme for the 3,500-square-kilometre licenses includes further data gathering, seismic work and analysis on the existing discoveries.

Increase in oil production offsets Spitfire's losses

March 3, 2008. Spitfire Energy produced an average of 289 barrels of oil equivalent per day, achieving revenue of $1.3 mn. Most of the production consisted of crude oil from the Company's wells in Saskatchewan. Spitfire evaluated a portfolio of assets for potential acquisition, targeting assets that offer a predictable production base with a mixture of exploration and development upside. The Company dedicated resources to its Fosterton, Saskatchewan optimization project. The Company is on track to have the capacity to handle the fluids for new development drilling by the end of the fiscal year. The increase in oil production offset declines in gas production. As result, revenue increased 9% to $1.3 mn. The Company continues to shift its production to take advantage of record high crude oil prices, with more than 77% of Spitfire's production now weighted to oil. In the third quarter, the Company evaluated a portfolio of assets for acquisition. Spitfire continues to look for assets that offer a predictable production base with a mixture of exploration and development upside.

Baker Hughes rigs actively looking for oil, gas drops

February 29, 2008. According to Baker Hughes Inc. the number of rigs actively exploring for oil and natural gas in the United States dropped by eight this week, to settle at 1,763. Of the rigs running nationwide, 1,418 were exploring for natural gas and 337 for oil. A year ago, the rig count stood at 1,752. Of the major oil- and gas-producing states, New Mexico gained three rigs, and California added two. Texas lost seven rigs, Alaska is down three, Colorado and Wyoming each lost two and Oklahoma declined by one rig. The Louisiana rig count is unchanged. Baker Hughes has tracked rig counts since 1944. The tally peaked at 4,530 in 1981, during the height of the oil boom. The industry posted several record lows in 1999, bottoming out at 488.

Premier awarded new production sharing contract in Vietnam

February 28, 2008. Premier Oil reported the award of a 50% operating interest in Block 104-109/05 on the western flank of the Song Hong Basin offshore of Northern Vietnam. A joint study between Premier and Petrovietnam has identified numerous leads on Block 104-109/05 in water depths ranging from 20 metres to 60 metres. The PSC carries a firm work commitment of seismic acquisition plus one exploration well. Mitsui Oil Exploration Company (MOECO) has a 50% interest in the Block 104-109/05 Joint Venture. Under a farm in agreement with Premier, MOECO will carry Premier on the first exploration well drilled on Block 104-109/05. Premier is building a new core business in Vietnam with oil field development underway on Block 12W, exploration drilling in Block 12W beginning in March and seismic acquisition in Block 07/03 commencing in July. The award of Block 104-109/05 adds significant prospectivity to Premier's Vietnam exploration portfolio.

PetroChina looking to build refinery in Singapore

March 3, 2008. PetroChina Co. Ltd., is looking to build a refinery in Singapore that will cost billions of dollars. It is currently doing a feasibility study and doing due diligence on this and so far the feedback has been positive. The Beijing-based company is looking to build a refinery with a capacity of at least 400,000 to 500,000 barrels per day.

Repsol-YPF to double Cartagena refinery capacity

February 28, 2008. Repsol-YPF SA, planning to double the capacity of its 100,000 b/d Cartagena refinery in Spain, has awarded a $1.3 bn contract to Fluor Corp. for the project management of much of the project. The $4.8 bn project represents the largest refinery upgrade and expansion project in Spain in the past 30 years. The project includes the design and construction of new units and the refurbishment and expansion of existing units, as well as construction of utilities and offsites. Groundbreaking is scheduled for early 2008, with construction completion and commissioning expected in 2011.

Gazprom cuts gas supplies to Ukraine

March 4, 2008. Russian energy giant Gazprom announced a further reduction of gas supplies to neighboring Ukraine over an unresolved payment dispute. As of 1700 GMT, exports to Ukraine would be reduced by 25 percent. Gazprom's two gas supply chops to Ukraine came one day after Russia reduced gas deliveries to Ukrainian natural gas distribution company Ukrtranzgaz by an initial 25 percent. As a result of the three reductions, Russian gas supplies destined for the Ukrainian market had been reduced by a total 75 percent from normal levels. Gazprom was continuing to pump gas to European consumers in unchanged volumes. The Kremlin-controlled energy conglomerate has argued Ukraine owes as much as US$1.5 bn, Ukraine owes for gas consumed since the beginning of 2008. Ukrainian government officials called on Gazprom to return to talks, before the cut back affected supplies to Europe. The gas conflict escalated in spite of the declaration by presidents Vladimir Putin and Viktor Yushchenko on February 12 that the dispute had been resolved. Gazprom and Naftohaz Ukrainy traded new accusations that, among other charges, their counterparts are refusing to forward billing information, and so blocking an early resolution of the crisis. The delivery reduction to Ukraine potentially could pare down gas supplies to European consumers, as Ukraine in previous conflicts with Gazprom has siphoned off gas destined to Europe for its own needs. It would cover gas shortfall from internal reserves, but left open the possibility of a reduction of gas volumes for Europe. Some 80 percent of Gazprom gas travels to the European Union via Ukrainian pipelines, providing Europe some 25 percent of its gas needs. A similar gas cut-off by Gazprom in late 2005 over a price dispute reduced volumes of fuel delivered to Europe for two days, and forced price spikes as far away as France.

Indonesia's PGN to build 3 LNG receiving terminals

March 4, 2008. Indonesian gas distributor PT Perusahaan Gas Negara is planning to build three LNG receiving terminals at a combined cost of US$1.67 bn. One LNG receiving terminal will be built in West Java at an estimated cost of US$650 mn. The LNG receiving terminal will be constructed in three stages the first stage with a capacity to store 200 mmscfd of gas is expected to be completed in 2012. The second stage with the same capacity is expected to be completed in 2018, while the third stage with a capacity to store 400 mmscfd is expected to be completed in 2024. PGN will also build one LNG receiving terminal in the East Java province at an estimated cost of US$574 mn. The terminal will be constructed in two stages the first stage with a capacity to store 200 mmscfd of gas is expected to be completed in 2011 and second stage with a capacity of 200 mmscfd would be finalized in 2017. PGN will also build one LNG receiving terminal in North Sumatra's town of Medan at an estimated cost of US$446 mn. The terminal, which will have a capacity to store 200 mmscfd of gas, is expected to start commercial operations in 2011, pending the completion of a gas pipeline linking the towns Duri and Medan. PGN expects its gas sales volume to hit 716 mmscfd this year compared to 413 mmscfd at the end of last year.

Valero wins fuel supply contract from DoD

March 4, 2008. The U.S. Department of Defense announced that San Antonio-based Valero Marketing & Supply Co. is being awarded a maximum $30,268,650.00 fixed price with economic price adjustment, indefinite delivery, and indefinite quantity contract for diesel fuel and unleaded gasoline. Other locations of performance are Corpus Christi and Pasadena, Texas.

State deptt set to issue permit for Keystone

March 4, 2008. The U.S. State Department intends to issue a permit this month for a $5.2 bn pipeline that would transport crude oil from Canada through seven states. If no other federal agency objects, a permit will be issued within 15 days for the Keystone pipeline, a project of TransCanada Corp. (TRP) of Calgary, Alberta. A permit would allow the project to move forward this spring. The entire 2,148-mile pipeline will be able to carry 590,000 barrels of oil daily by late 2010. Canadian regulators already have approved the route through Canada. The pipeline will be equally owned by TransCanada and Houston-based ConocoPhillips (COP). It would carry crude oil across Saskatchewan and Manitoba, and through North Dakota, South Dakota, Nebraska, Kansas, Missouri, on the way to refineries Patoka, Ill., and Cushing, Okla. Because it crosses the U.S.-Canadian border, the project requires a presidential permit from the State Department. The department in January issued a statement saying the pipeline would result in limited environmental harm. The company plans to start work on the pipeline this spring and complete it in 2009. The company is expecting crude to be piped to the refinery in Illinois late next year, and to the refinery in Oklahoma a year later.

Dana gas, Emarat form JV for gas pipeline

March 3, 2008. Dana Gas, the Middle East's first regional private-sector natural gas company, and Emirates General Petroleum Corporation (Emarat), have agreed to establish a joint venture to own, manage and operate the Middle East's first common user gas pipeline, which will be completed in March this year. Dana Gas and Emarat, along with the three end-users the Federal Electricity & Water Authority of the UAE (FEWA), the Sharjah Electricity & Water Authority (SEWA), and Dana Gas affiliate Crescent Natural Gas Company Limited (CNGCL) signed a Memorandum of Understanding (MoU) for the implementation and utilization of the pipeline in January 2006. Dana Gas and Emarat each have a 50 percent stake in the construction, ownership and operation of the pipeline. Phase one of the project was completed in May 2006 and has since been delivering gas to the SEWA power station at Hamriyah. The main pipeline of the joint Hamriyah Gas Pipeline Project is a 48-inch gas pipeline that connects the Sharjah gas hub at Sajaa to the fast-growing industrial area at Hamriyah, and covers a distance of 32 km, with a capacity of one bcf per day. Soon after its completion in March this year, the 48-inch pipeline will deliver gas supplies to the three end-users. This project is a prime example of the solutions that can be achieved through the cooperation of government and private sector entities. The strategic partnership between the two companies for this project in the UAE has been very positive and has laid the groundwork for future projects throughout the region.

Nigeria reports $13 bn price tag for TSGP

February 28, 2008. The Trans-Saharan Gas Pipeline Project, or TSGP, will cost $13 bn and will deliver its first gas in 2015. Nigeria, Algeria and Niger have agreed to spend $10 bn on the project and $3 bn has been set aside for gas gathering. The 4,400 kilometer pipeline will transport 20 bcm to 30 bcm of natural gas from Nigeria to Europe through Niger and Algeria, the Nigerian National Petroleum Corp. The gas is to be exported to Europe. Nigeria would be setting aside between 13 and 15 tcf of gas for the project for the first 25 years. Nigeria's gas reserves are estimated at 184 tcf, but industry officials have expressed doubt the country can produce adequate gas for TSGP given the current shortage of gas for domestic use.

Victory energy starts production from new gas well

February 27, 2008. Victory Energy Corporation reported that the first gas well the Corporation drilled in the Adams-Baggett Canyon Sandstone gas field in Crockett County, Texas has been brought online February 26. Victory's newest gas well is producing from the Canyon Sandstone gas zone. The gas well began flowing gas to surface on its own. Sales of the gas into the market started immediately.

China orders Sinopec, CNPC to guarantee supplies to small firms

March 4, 2008. China's two big oil companies, the China Petroleum and Chemical Corporation (Sinopec) and the China National Petroleum Corporation (CNPC) have been ordered by the government to guarantee oil supplies to small and independent wholesalers and retailers. According to a notice issued jointly by the state planner, the National Development and Reform Commission (NDRC), and the Ministry of Commerce, both companies were obliged to sign long-term supply contracts with qualified private firms. The price of the oil supplied to private wholesalers will be 5.5-7 percent lower than the state-set retail guidance price, while the price of oil products supplied to independent gas stations must be at least 4.5 percent lower than the guidance price. State-owned Sinopec and CNPC have held a virtual duopoly over crude oil production and refining in China since 1998, when the government decided to crack down on market disorder in the sector by designating oil as a strategic national resource and declaring all private exploration illegal. China's private oil sector has therefore been almost entirely dependent on the two companies for their supplies. High international crude oil prices, coupled with fixed domestic retail prices, have meant that the refining segments of CNPC and Sinopec have been operating at a loss in recent years. Last year, the two companies were accused of reducing refining output in order to minimize their losses, thereby cutting off supplies to small wholesalers and retailers and leading to crippling nationwide diesel and gasoline shortages. The government finally responded by raising product oil prices by 500 yuan per ton at the beginning of November. Since last summer, representatives of China's private oil enterprises, many of which have faced closure, have been urging the government to step in to guarantee supplies. However, the government's long-term aim remains the consolidation of the sector in the hands of CNPC and Sinopec. The NDRC notice called on the two oil majors to speed up the restructuring of the sector through mergers and stake purchases in smaller operators.

Eni to put $4bn into Venezuela oil project

March 3, 2008. Eni, the Italian oil and gas group, plans to invest $4 bn in Venezuela, the biggest commitment to the country by a western oil company since President Hugo Chávez began to take control of its oil projects in 2005. Eni has reached agreement in principle with PDVSA, Venezuela's state-owned oil company, to develop an area of the Orinoco belt, one of the world's largest oil reserves. The deal is the most concrete sign yet of Venezuela's enthusiasm for foreign investment to revive its ailing oil industry. It also reflects Eni's strategy of being among the first big oil companies to invest in politically risky countries. The investment would expose Eni to the risk of further expropriation by Chávez, while giving it increased access to Venezuela's huge reserves ahead of its European and US competitors. Other western oil companies, including StatoilHydro, Total and Royal Dutch Shell, have signed preliminary agreements to look at investment in Venezuela. Eni hopes to begin production at a rate of 30,000 barrels per day in 2010, and step up to 300,000 b/d by 2014. PDVSA would have 60 per cent and Eni 40 per cent of the joint venture. The total investment is estimated at $10 bn.

Questar in position to grow production 16 pc in ’08

March 3, 2008. Questar has revised 2008 earnings and production guidance and underlying assumptions to incorporate newly acquired properties, the recent increase in natural gas and crude oil prices, and additional natural gas fixed-price hedges. Questar E&P has now hedged about 78% of forecast natural gas and oil-equivalent production for the remainder of 2008 with fixed-price swaps. Additionally, the company has hedged about 2% of its forecast natural gas production for the remainder of 2008 with basis-only swaps. The company estimates that a $1.00 per mmBtu change in the average NYMEX price of natural gas for the remainder of 2008 would result in about a $0.02 change in earnings per diluted share. A $10.00 per bbl change in the average NYMEX price of oil for the remainder of 2008 would result in about a $0.05 change in earnings per diluted share. The company has added 11 bcf of natural gas fixed-price swaps for the remainder of 2008, 28.1 bcf for 2009, and 28.4 bcf for 2010 since it last disclosed hedge positions on February 12, 2008.

Addax, Kurdistan amend Taq Taq PSA

February 29, 2008. Addax Petroleum Corporation has signed an agreement with the Kurdistan Regional Government (KRG) amending the production sharing contract it holds together with Genel Enerji in respect of the Taq Taq license area in the Kurdistan Region of Iraq. The Taq Taq license area includes the Taq Taq field and the Kewa Chirmila prospect. The purpose of the amendments is to bring the Taq Taq PSC into conformity with the Oil and Gas Law of the Kurdistan Region, Iraq and Model PSC, including the royalty, cost recovery and profit share components. The review and renegotiations were conducted between the KRG, Genel Enerji and Addax Petroleum in accordance with Article 54 of the Oil and Gas Law which required review of the Taq Taq PSC by the Regional Council for the Oil and Gas Affairs of the Kurdistan Region, Iraq (the Regional Council), taking into consideration the prevailing conditions when the Taq Taq PSC was originally entered into. The most significant changes to the terms of the Taq Taq PSC include:

i)              the combination of previously separate terms for the Taq Taq and Kewa Chirmila areas, including the synchronization of the government back-in rights at up to 20 per cent,

ii)             a reduction in the maximum Cost Oil recoverable in a given year, which is partially offset by an effective increase through an interim period that accelerates the recovery of the initial capital investment by the Contractor, and

iii)           the introduction of a "R factor" in the Profit Oil calculation, which adjusts the financial returns to the Contractor and Government based on relative level of cumulative capital spending and cumulative revenue.

The ultimate financial impact of the amendments to the terms of the Taq Taq PSC is dependent on operational outcomes, including reserve, production and cost levels. However, the Corporation believes that under most of the likely scenarios and considering the further exploration potential of the PSC area, the amendments do not result in a material change to the financial or operational interests of Addax Petroleum.

Canada warns US against energy law barring fuel from oil sands

February 28, 2008. The Canadian government is urging the United States to avoid an expansive interpretation of a new U.S. energy law that could block government purchases of fuels derived from Alberta's booming oil sands region. Section 526 of the law that President Bush signed last December bars government contracts for alternative fuels including non-conventional petroleum sources whose lifecycle emissions of heat-trapping greenhouse gases exceed those of conventional fuels. Canada would not want to see an expansive interpretation of Section 526, which would then include commercially available fuel made in part from oil derived from Canadian oil sands. The provision is apparently aimed at fuels other than those which are commercially available as part of the stream of petroleum fuels. Canada does not consider oil extracted from the sands to be alternative fuel, noting it is commercial and processed in conventional refineries. The letter acknowledges that oil sands production has higher greenhouse-gas emissions than conventional crude but adds that Canada and Alberta are committed to curbing emissions. Canada is the largest U.S. oil supplier. It sent 1.8 million barrels per day of crude oil and 500,000 barrels per day of refined products to the United States in 2006. About half of Canadian crude is derived from oil sands, with sands production forecast to reach about 3 million barrels per day in 2015. Environmentalists and their allies in Congress are getting worried about greenhouse gases from oil sands production as well as potential emissions from proposed plants that would make liquid fuels from coal. Without controls on emissions of carbon dioxide, these sources have higher emissions than conventional fuels.

Russia, Hungary conclude South Stream deal

February 28, 2008. Russia sealed a crucial deal with Hungary in its race with the European Union to build a new natural gas pipeline to supply Europe. President Vladimir Putin signed a bilateral agreement with Hungarian Prime Minister Ferenc Gyurcsany at the Kremlin to move forward with the South Stream pipeline. The agreement settles a part of the pipeline to carry a projected 10 billion cubic meters of gas per year through Hungary after travelling through Bulgaria and Serbia - both of which signed onto the project in the past month. Russian energy giant Gazprom's push to build South Stream is widely seen as an effort to foil the US-backed EU project to build an alternative pipeline and so preserve its monopoly on gas export pipelines to Europe. Russian gas accounts for about 40 percent of the EU's imports.

POWER

China to build first inland nuclear power plant

March 4, 2008. China Guangdong Nuclear Power Group (CGNPG) and the Hubei provincial government on signed an agreement here to build the country's first inland nuclear power plant. The project will be located in Xianning City, 421 kilometers southeast of Yichang City where the Three Gorges Dam lies. The CGNPG declined to reveal the investment and scale of the project, as well as when it would start construction. China currently has 11 nuclear generators in six nuclear power plants, all located along the eastern coast, with a combined installed capacity of 9.07 million kW.

The CGNPG's installed capacity is 3.95 million kW, or 43.5 percent of the total. Faced with an energy crunch resulting from its fast economic growth, China has decided to develop more nuclear power. By 2020, the nation will have an installed nuclear power capacity of 40 million kW, accounting for 4 percent of its total installed generating capacity. At present, another 12 nuclear generating units have been approved for construction, with a combined power capacity of 12.24 million kW.

Coal-fired South Dakota power plant awaits approval

March 4, 2008. Minnesota's push to drastically cut state greenhouse gas emissions is being felt next door in South Dakota and that may be a problem for its neighbors. A hoped-for power plant expansion has been approved by South Dakota's regulators, but plans to run powerlines deep into Minnesota have faced opposition from environmentalists who say it runs counter to Minnesota's move toward cleaner power. While Minnesota has a plan to cut greenhouse emissions by generating 25 percent of its energy through clean sources like wind by 2025, South Dakota has set no such standard. As early as April, the Minnesota Public Utilities Commission will decide whether to grant permission for expansion at the project near Milbank, S.D.

Without Minnesota's backing, the so-called Big Stone II project which would serve 1 million people, about half of them on the western plains of Minnesota will be sunk. The latest modeling plan considered whether the plant expansion could generate the electricity it needs at a cheaper cost using wind, and determined it could not. The company believes it has included an accurate projection of future carbon penalties in its costs. Three years ago, seven regional power companies announced plans to expand the plant near Milbank, which first began producing power in 1975. Initial plans calling for a 630 MW plant were scaled back to between 500-580 MW, and two companies have since dropped out of the project. The plan angered small-town environmentalists, advocacy groups and lawmakers who argue that feeding the plant's power to Minnesota cities would violate the spirit of its renewable energy standard, which was passed just last year.

North West shelf LNG formalizes deal with Chubu Electric

March 4, 2008. Japan's Chubu Electric Power Co. has formalized an agreement to buy about 500,000 metric tons of liquefied natural gas a year from Australia's North West Shelf project. The North West Shelf LNG Venture has signed a sales and purchase agreement to supply the LNG for seven years from April 2009 on an ex-ship basis. An initial agreement for the LNG was signed in October 2006 and it brings Chubu's total purchases from the project to 1.1 mtpa from April 2009. The six equal partners are operator Woodside Petroleum Ltd., BHP Billiton, BP Plc, Chevron Corp., Royal Dutch Shell and Japan Australia LNG.

Australian flooding, declining Chinese inventories to lift coking coal price

March 4, 2008. Coking coal prices are expected to heat up, as further flooding in Australia and declining inventories in China weaken global supply of the fossil fuel. In a note to clients, Essentially freeing companies from liability or obligation when an extraordinary event or circumstance happens beyond their control. As a result of both situations, UBS raised its 2008 coking coal price forecast from US$170 per tonne to US$225 per tonne. Teck Cominco Ltd. and Fording Canadian Coal Trust will benefit from the increase, but cautioned the gains from higher coking coal prices likely would not be seen until the second half of 2008, as earnings at both companies will be affected by carry-over tonnage priced at US$91.

Gazprom to control coal and electricity markets

February 28, 2008. Russian energy majors Gazprom and SUEK had agreed on the main terms for merging their power and coal assets. The merger will create a $16 bn holding company, Russia's largest so far. The controlling stake (50% plus one share) will be held by Gazprom. Gazprom had been negotiating the merger with the Siberian Coal Energy Company, or SUEK, for a year. SUEK is the country's largest coal producer and one of the world's top ten in terms of coal production. Gazprom, too, is not only the world's largest gas producer, it now also controls impressive power generation assets it bought up during the reform of RAO UES, Russia's recently reorganized energy monopoly. The resulting bundled company will be Russia's largest energy holding, encompassing power plants accounting for 15% of Russia's electricity market, and 5.8 billion metric tons of coal reserves with annual production potential of around 90 million metric tons.

Orion to hike electricity prices

February 28, 2008. Canterbury electricity line operator Orion will up its prices by 5% on April 1. 3.5% of that is due to the increasing cost of construction and wages. The rest is due to increasing Transpower costs which owns and operates the national grid. The pressure on all electricity retailers to put their prices up is increasing and he believes consumers around the country will eventually be paying $4 more a month. This increase will not kick in for a few months yet as electricity retailers usually up their prices in spring.

Nuclear regulatory framework on cards

March 3, 2008. The Ministry of Mines and Energy of Namibia will develop a nuclear regulatory framework for it to pursue nuclear power as a long-term solution to the electricity shortage in the country. This will also allow for the processing of Namibia's uranium resources, which are presently exported as yellow cake. Cabinet recently approved that the ministry should develop the framework for the country to use its resource to solve its electricity crisis. Namibia, like other countries in the southern African region, faces a shortage in electricity because of lack of generation capacity, which may go on for years. Beneficiated uranium product fetches N$3000/kg compared to US$100/kg for yellow cake. Apart from generating clean energy, Namibia could qualify to earn carbon credits. But before Namibia can build nuclear power stations, or uranium processing plants, it needs a nuclear regulatory framework that will be developed in conjunction with the International Atomic Energy Agency. In this case, experts will have to work with legal drafters from the Office of the Attorney General on the framework that provides for nuclear safety, to cover duties and responsibilities of nuclear regulation, nuclear energy and stating the Government's requirements for the licensing, building, commissioning, operation and decommissioning of all nuclear establishments and procedures of transporting and strong waste. The framework will also have to include restrictions, and accountabilities associated with nuclear non-proliferation. Namibia produces 384 MW of power from local plants, but has a daily maximum requirement of 450 MW, with the extra load imported from South Africa, Zimbabwe and Zambia. The Government last year declared a moratorium on the issuing of uranium prospecting licences to regulate the activities because of an upsurge of demand in the global market for the resource, considering that uranium is not only used for electricity generation but also for destructive purposes. Namibia contributes around eight percent of global uranium production and with the opening of new mines in future, the country is likely to produce 15 percent of the world's demand.

Egypt plans to provide all of Gaza's electricity

February 28, 2008. Egypt is working on a plan with the Palestinians to supply all the besieged Gaza Strip's electricity needs and wean it off its reliance on Israel for power. Earlier this month, Israel began reducing its supply of electricity to the Hamas-ruled coastal strip after the High Court of Justice ruled that doing so would not cause a humanitarian crisis. Israel's plan includes gradually reducing the electricity supply by small increments, in efforts to pressure the Hamas government to prevent Qassam rocket fire from the Strip into southern Israel. So far, Israel has supplied most of the electricity utilized in Gaza. Egypt's Electricity Ministry is preparing a study with President Mahmoud Abbas' Palestinian Authority on financing the project and providing equipment to Gaza. The project would take at least six months to implement, though he could not say when it would start. An official at the ministry confirmed that Egypt was exploring means of providing all of Gaza's electricity needs. Ten of the 17 power lines supplying Gaza currently come from Israel, five from a local power plant and two from Egypt. Gaza's consumption increases by about 10 percent a year, and the strip currently needs about 240 MW. The proposal would bolster Abbas' claim to represent Gaza. Abbas now rules from the West Bank and wields little control over the Hamas-held Gaza.

Chhattisgarh Jatropha plan derailed

March 4, 2008. Commercial production of bio-diesel in Chhattisgarh would start once the production of Jatropha seeds increased in the state. The only bio-diesel production plant set up near the state capital is for demonstration. It has produced 2494 litres of bio-diesel so far. Once the production of Jatropha seeds increased, the state would start the commercial production to become the bio-fuel model state in the country. Besides delegates from different countries, representatives of 26 states and experts from Indian Institute of Technology (IIT), Kharagpur have visited the plant so far and studied the process of producing bio-fuel.

The state government had set a target to produce 200 mn saplings of Jatropha in the current financial year. As of now, 180 mn saplings had been produced in different nurseries of the department of forests. The state government had taken up extensive programme to promote the cultivation of Jatropha in the state. Under the policy drafted by the government, it would provide 500 Jatropha saplings free of cost to any farmer interested in taking up its cultivation.

Branson keen on algae-based bio-fuel

March 3, 2008. After flying the first commercial airplane on bio-fuel, Richard Branson has hinted at developing fuels from algae that does not compete with food and is not environmentally damaging. And the UK billionaire thinks that India has potential to develop such algae-based bio-fuel. The chances are that it would not be coconuts. The bio-fuel for Branson’s Virgin Atlantic Boeing flight from London to Amsterdam on February 24, came from a blend of coconut and babassu oil. This includes global warming, conflict situations and developing clean fuels. The five degree increase in global warming could also affect India. 

EnviTec Biogas awarded €30 mn biogas contract in India

February 29, 2008. EnviTec Biogas company has been awarded a €30 mn (US$45.5 mn) contract in the dynamically growing Indian market for the first time via a 50 percent joint venture in that country. The company will build 30 biogas power plants in Punjab to deliver renewable electricity and heat from biomass to rural populations across the state. India has gigantic energy requirements as one out of two households in rural regions does not have any electricity. According to the PEDA, bioenergy is by far the renewable with the largest potential in the state. Biogas holds a potential of around 160 MW and room for around 425,000 small household-scale biogas plants, biomass can contribute 1000 MW of power, co-generation from the sugarcane sector 140 MW and energy from MSW around 100 MW. With a total value of over €30 mn, the contract provides for the delivery of 30 one MW biogas plants, which are to be assembled across Punjab over the next two years. Work on building the first few plants is to commence in March of this year.

Generating electricity from biogas is part of a 160 MW renewable energies project which the consortium Green Planet Energy Pvt. Ltd, in which EnviTec Biogas is involved, has been awarded. EnviTec Biogas AG covers the entire value chain for the production of biogas, including the planning and turnkey construction of biogas plants as well as their commissioning. The company provides the biological and technical service and also offers the full plant and operating management. In addition, EnviTec also operates its own biogas plants. In Penkun, in the German state of Mecklenburg-Western Pomerania, EnviTec is currently constructing what it believes to be the world's largest biogas park with an electrical connected load of 20 MW. EnviTec is represented through its own subsidiaries, joint ventures or sales offices in the Netherlands, Italy, the UK, Hungary, the Czech Republic, the Ukraine, Romania and India. In Belgium, Croatia and Greece, the company is already in the process of planning and constructing biogas plants.

Petrobras forming single biofuels business

March 4, 2008. Petrobras approved the creation of a company, a wholly owned Petrobras subsidiary, to undertake Biofuels activities. These attributions are currently spread among several company areas and subsidiaries, rendering management more difficult to perform. The new company will absorb both ethanol production and biodiesel input acquisition and processing, currently done directly by Petrobras, in addition to future investments. The purpose of this incorporation is to coordinate all biofuel productive chain activities in Brazil and abroad. Ethanol and biodiesel marketing and logistics, in Brazil and abroad, will remain under the Downstream area's responsibility. Petrobras' Strategic Plan calls for global performance in biofuel marketing and logistics, leading the Brazilian biodiesel production, and for boosting its share in the ethanol business, with investments forecasted at $1.5 bn through 2012.

Technip wins Malaysia biodiesel contract

March 4, 2008. KNM Process Systems Sdn Bhd has awarded Technip a contract to provide assistance in the detailed engineering of the fatty acids methyl ester transesterification unit for a biodiesel production plant to be located at the port of Kuantan, Malaysia. This project will be executed by Mission Biofuel Sdn Bhd (investor), KNM (contractor) and Axens (licensor). The unit will produce 250,000 tons of biodiesel per year from palm oil. It is scheduled to go into production in the third quarter of 2008. Technip's operating center in Kuala Lumpur (Malaysia) will execute this contract with assistance from the Groups operating center in Paris, which has already built six production units in this sector of activity.

China’s installed wind power capacity to exceed 5 mn kW by ’10

March 4, 2008. Thanks to policy, electricity price, technology and other supporting capacity, China's installed capacity wind power will exceed five mn kW by 2010, the National Development and Reform Commission predicts. It is forecast that the newly increased wind power installed capacity reached 2.4 mn kW in 2007 and the total installed capacity hit five mn kW toward the end of 2007. In addition, many domestic wind power facility producers plan to start new projects or expand production. The newly increased installed wind power capacity will be four mn kW in 2008, 5.5 mn kW in 2009 and seven million kW in 2010.

Arava to get $2.5 bn solar station

March 4, 2008. An international project management firm has recently signed a memorandum of understanding for construction of a $2.5 bn solar power station at Eilot Region in the Arava desert. The extravagant project, which is expected to continue over a five-year period, involves installation of photo-voltaic (PV) panels which will eventually supply up to 500 MW of electricity. The agreement was signed by Arava Power of Kibbutz Ketura located in the southern Arava.

Representatives of the international firm have visited Israel on a number of occasions to promote the project. The project, however, is contingent upon the Electric Company paying a higher price for the solar energy that the power station produces. An electricity producer currently gets 22 cents per kilowatt-hour electricity produced by all types of technology. PV production of electricity becomes financially feasible at rates of 37 cents per kW/hr.

According to the plan, solar panels are to be installed along thousands of dunams the length of the Arava and on the border with Jordan, and may in the future cross the border. Meanwhile, Arava Power, is promoting a power station that will supply 2.5 megawatts from an 80 dunam area on Kibbutz Ketura designated for industrial use.

The Eilot Regional Council has been lobbying for a move that will allow kibbutzim in the area to sell electricity at NIS 2.04 per kW/hr, the new rates issued by the Electricity Authority for home and industrial consumers who install solar panels for production of electricity. The arrangement is meant for private consumption, with any surplus being transferred to the electrical grid. Home consumption facilities are limited to 15 kW-hr, and 50 kW-hr for industrial consumers.

Energy Quest in biomass venture in Chile

March 3, 2008. Energy Quest expects to enter into a joint venture with Etanol Del Pacifico Sur for the construction of an 82,000 liter per day plant in Las Cabras, with Energy Quest holding a 60 percent stake and Etanol Del Pacifico Sur, a corn farmers association, holding 40 percent. The implementation of this technological innovation in the country will surely mark a milestone for the development of ecological fuels in the whole region.

 Energy Quest will provide the proprietary technologies and equipment for the plant, while Etanol Del Pacifico Sur will provide the feedstock of waste biomass from its existing corn growing operations. Commissioning and start up of the facility is expected within 12 months from the signing of a joint venture agreement.

Fuel cells already delivering electricity, hot water to Japanese homes

March 3, 2008. About 2,200 homes in Japan get electricity and heat water with power generated by a hydrogen fuel cell. The technology which draws energy from the chemical reaction when hydrogen combines with oxygen to form water is more commonly seen in futuristic cars with tanks of hydrogen instead of gasoline, a key culprit in pollution and global warming. Developers say fuel cells for homes produce one-third less of the pollution that causes global warming than conventional electricity generation does. The plain gray fuel cell is about the size of a suitcase and sits just next to a tank that turns out to be a water heater.

In the process of producing electricity, the fuel cell gives off enough warmth to heat water for the home. Another machine in the gray box cleans adds oxygen to make the carbon monoxide into carbon dioxide. Even though carbon dioxide contributes to global warming, it is not poisonous. The entire process produces less greenhouse gas per watt than traditional generation. Nearly every home in Japanese cities is supplied with natural gas, which could make it relatively easy to spread fuel cell technology there. The potential for widespread use of fuel cells in bigger or more sparsely settled countries is less certain. Many American homes do not have gas service.

Farmers debunked Los Banos study on Jathropa

March 2, 2008. Several militant farmer groups in Negros Oriental had debunked claims of an earlier study by a team from University of the Philippines Los Banos in Laguna, which favorably endorsed Jathropa plantation and claimed that it will not affect food production. Fermin S. Lorico, chairperson of the District Farmers Alliance (DFA) emphasized that the study itself is based on falsities and incorrect assumptions just to favor and legitimize the planting of Jathropa in connivance with big businesses and the government to the detriment of the interest of the farmers. The non-cultivation, Lorico explained was due to the absence of government support services.

Saudi Arabia to step up investments in solar power

March 2, 2008. Saudi Arabia, the world’s biggest oil exporter, plans to become an expert in another, cleaner field of energy by investing in solar power. One of the research efforts that the country is going to undertake is to see how it becomes a centre for solar energy research and hopefully over the next 30 to 50 years it will be a major megawatt exporter. In the same way can also be an exporter of power. Saudi Arabia produces more than 10 million barrels of crude oil a day. The country was also set to invest in carbon capture and storage programmes to develop technology allowing carbon dioxide to be extracted from the atmosphere and stored underground.

MTCC to offer green electricity to event planners

February 29, 2008. The Metro Toronto Convention Centre (MTCC) announced that it is the first convention centre in Canada to offer green electricity to clients and event planners to help them reduce the environmental footprint of their events. In addition, the MTCC will use green electricity to power its administrative offices and electronic signage. The MTCC has a long tradition of providing leadership in the area of environmental stewardship, and has won numerous awards for its efforts in recent years. The MTCC has been recognized for its Zero Waste Event concept, for its massive green roof and for being among the first to utilize Toronto's Deep Water Cooling system, among many other initiatives. Founded in 2005, Bullfrog provides homes and businesses with an easy way to go green and help create a cleaner, healthier environment for future generations. In Ontario, all of Bullfrog's power comes from clean, renewable EcoLogo(M) certified wind power and low-impact water power, displacing polluting and carbon-intensive sources like coal. Under this innovative agreement, Bullfrog will work with the MTCC to calculate the expected electricity usage of participating events. Bullfrog will then inject the equivalent amount of clean, renewable power onto the provincial electricity system on behalf of the event. In addition, Bullfrog will supply the MTCC with about 577 MW hours of green electricity per year to power the Centre's own administrative offices and electronic interior and exterior signage throughout the building. This is expected to reduce the facility's electricity-related CO2 emissions footprint by another 126 tonnes annually.

Clay High sees electricity blowing in the wind

February 28, 2008. Clay High School plans to begin research in April into the viability of wind energy as an alternative energy source in Oregon. The city's planning commission last week approved a zoning permit for the high school to build more than one wind turbine on its property for the purposes of research. The school plans to build at least two electricity-generating wind turbines, costing more than $35,000 each. No taxpayer dollars are being used in the project, which is entirely funded through private donations.

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