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No Weather Vane of a Gas Policy, Please
Sunjoy Joshi, Senior Fellow, Observer Research Foundation
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S THE FINANCIAL TURMOIL TAKES ITS toll on commodity prices, especially oil and gas, many are bound to question the logic of prices settled in different times and under very different circumstances. The harsh truth that these bargain hunters must understand is that in the oil and gas exploration and production business, while all the inputs by way of risks and investments are determined by the vagaries of markets, the outputs (discovery and production) are determined more by the uncertain laws of probability.
A regulated-price regime cannot provide a satisfactory risk-reward balance under these circumstances and spur investments and growth.
Many expert committees that went into the whole question of reforming the sector through the nineties have fully appreciated this reality. The nineties saw prices fall to such historic lows that upstream companies found themselves starved of capital to invest. This contraction in new upstream capacities in
The market-based pricing approach advocated under the New Exploration & Licensing Policy (NELP) met with success and it did dramatically transform perceptions about the prospects of
However, as gas production from KG D-6 block was about to commence, many analysts argued that with the high oil and gas prices prevailing across the world (spot cargoes being imported into India were priced at over $20 per mmbtu), the government needed to intervene and fix prices as low as possible to minimise its subsidy burden. Under stress, the government adopted a pricing formula that actually reduced the price proposed by the contractor and indexed the gas price under a formula to oil prices with a floor at $25 and a ceiling at $60, which corresponded to a gas price that would range between $2.5 and $4.2 per mmbtu as oil prices changed.
The government’s concerns about fixing a “reasonable” cap seemed understandable as oil prices began their surge to the $150 mark with most analysts betting on when they would scale the $200 threshold. The approved formula effectively isolated D-6 gas from the volatility of crude prices induced by market gyrations and insulated it from the vagaries of spot gas markets.
In their own interest, customers would prefer long-term contracts with predictable and stable prices to playing roulette, speculating on spot LNG prices. As the world enters a cycle where LNG supplies chase demand, there could be distress cargoes going for as low as $2.5 a mmbtu. However, it would be as foolish to prescribe gas prices using these levels as it would be to use $22 per mmbtu as a benchmark on the basis of prices touched in February 2008 for gas imports to consumers here. Leaving distress cargoes aside, existing term contracts for LNG still hover around $8 per mmbtu while those signed in the Asia-Pacific LNG market during the current year remain at about $7 per mmbtu. March naphtha prices averaging $403 per tonne still correspond to a gas price of $9.60 per mmbtu in oil equivalent terms. However, it is uncertain if the prices are going to stay at these levels or which direction they would start moving. The same analysts who are predicting a glut of global LNG till 2013 were until last July wondering where the LNG supplies for all the re-gas terminals being put up across the world would come from at least until 2015.
But away from the hurly burly of international markets and closer home gas from erstwhile discovered fields like PMT continues to be sold at $5.70/mmbtu and re-gasified LNG price is sold at a pooled price of $6.10, as a result of definitive interventionist policy decisions.
In short, with a strategic commodity like oil or gas, which the country has little hope to have enough of, we can ill-afford to adopt a weather vane of a policy. If the government feels it needs to regulate markets and intervene in determining prices that intervention has to be done with longterm policy objectives in mind that seek to sufficiently incentivise producers rather than be tuned to narrow objectives of keeping subsidy bills as low as possible. As it is ONGC loses Rs 2140 crore by selling gas at prices fixed under the notorious Administered Price Mechanism.
In a high risk business, where returns are predicated on probabilistic outcomes, producers need predictability and certainty in markets that are regulated, on one pretext or the other, through policy. The only other alternative available to policymakers is to shun national allocation priorities and quotas (as was indeed the original reforms mandate under NELP) and leave market forces free to determine prices.
Courtesy: Economic Times, April 9, 2009
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he hydrogen to carbon ratio in fuels used by mankind so far has progressively increased from 0.1 for wood, 1 for coal, 2 for oil and 4 for natural gas taking the world ever closer to decarbonisation. Natural gas is thus the ‘natural’ energy choice of this century. Natural gas has inherent advantages over other forms of fossil fuels. Burning natural gas hardly produces any sulphur dioxide, carbon monoxide or carbon dioxide compared to other forms of fossil fuels and its conversion efficiency is one of the best among energy sources. Increased use of natural gas in
Natural gas consumption in
Global in place reserves of natural gas are estimated to be about 6263 Trillion Cubic Meters [TCM]. Out of that, discovered 2P reserves stand at about 177 TCM. Even at an annual consumption of 2948 Billion Cubic Meters [
The Indian subcontinent is testimony to this conclusion. Within two years of opening up the Indian sedimentary basin for competitive exploration, the largest discovery of natural gas in the world for that year was made. So far about 500 BCM of gas reserves have been discovered in
On the basis of large discoveries already made, indigenous availability of gas, currently standing at about 90 metric million standard cubic metres per day [mmscmd] is likely to increase to about 170 mmscmd by the end of the 11th Plan. Gas production is likely to touch about 60
Source: Presentation by Shri V K Sibel, Director General, DGH
Four percent of the sedimentary basins of the world lie in
Among experts, there is 90 percent confidence that at least 1 percent of
This is a remarkable development in a country that was written off as unattractive in terms of hydrocarbon prospects ten years ago by all the international oil companies. Now most companies believe that basins around
Exploration for oil & gas in
Unlike some large gas deposits in Siberia and
Giant discoveries also mean super-giant challenges. Oil & Gas discoveries are made not merely by the use of superior technology but by the clever mix of technology and knowledge. This is the key to unlocking
Synergies between the industry, academia and policy makers are yet to be fully exploited in
A range of projections are available on future natural gas production and demand. If we go by the most optimistic projections, by 2011-12, the availability of natural gas would stand at about 279 mmscmd meeting a demand of roughly 281 mmscmd. However if we go by more pessimistic estimates for production along with the increased growth rate of
As far as
to be continued…
ORF-IEF Conference Summary Report November 2007
Sustainable Development of the Indian Coal Sector (part – V)
Ananth P. Chikkatur a,*, Ambuj D. Sagar b, T. L. Sankar c
Continued from Volume V, Issue No. 41…
3.1. Challenges for reducing socio-environmental impacts
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itigating the environmental impacts of mining activities must include reducing environmental impacts of establishing and operating the mine and post-closure reclamation. Mitigating the social impacts of mining must focus on two groups of projected- affected people: displaced people and project-affected local communities. For the former, ensuring adequate compensation for lost assets as well as providing opportunities to earn a livelihood that is at least comparable to (if not better than) the pre-displacement situation is a minimum. For local communities, community-development programs must ensure that they receive economic and other benefits from the presence of the mining project.
Some of the environmental impacts of mining can be mitigated through him proved mining and associated practices. For example, air pollution management strategies can include improved handling and transportation practices, spraying of water on roads, and the development of green belts [41]. Careful planning of mine development and subsequent mine closure can also help reduce environmental impacts. Planning for reclamation of the mine after its closure must be an integral part of mining development planning. In addition, it is important to include systematic monitoring and verification program to make sure that the initial promises are fulfilled. Innovative approaches to ensure compliance with plans may be useful—for example, one possibility could be to requirement the posting of an interest-earning ‘‘reclamation bond’’ prior to mining that could be returned on the successful reclamation of the mined land.27
Another area of some contention is the environmental impact assessment (EIA) process. MoEF has to give an environmental clearance, based on the environmental impact assessment for mining project before it can be approved.28 The EIA and subsequent public hearing process is expected to allow for the consideration of the environmental issues and take input from local communities; however, analysts have pointed out that the EIA process has been subverted in many cases.29 While there have been significant efforts to improve EIA processes, much could still be done [45]. Improving the public hearing process is an important issue to ensure that the social and environmental concerns from local project-affected people are heard. However, the public hearings become contentious, as stakeholders often have divergent interests and goals, and environmental issues might get sidelined. One option would be to video tape these hearings to provide a more objective perspective of the public hearing process for decision-making committee in MoEF.
Another key issue (particularly for the mining industry) is the long time taken by the MoEF to give EIA approval for projects. While it is important to reduce unnecessary bureaucracy and reduce the length of time taken to provide EIA approval, care must also be taken that ‘‘improving’’ of EIA processes does not short change the scrutiny required of the complex and varied impacts that could potentially result from a mining project. A careful assessment is needed to understand the reasons why the current EIA procedure stake the length of time that they do.30 The EIA and the public hearing processes should be taken seriously by the industry, government, and affected public, and should be viewed as a platform for collaboration between central government agencies (and industry) and those who will bear the environmental, social, and economic costs of projects.
There is a need for new ideas to help advance the development of mining projects while safeguarding the environment. In this vein, one idea proposed by the Working Group for Coal and Lignite for the 11th Plan is the notion of ‘‘green credits,’’ which is intended to reduce the delay caused by the need show equivalent land for compensatory afforestation before a project can be approved [60]. Such an approach would allow coal mining companies to take up afforestation in advance and be given ‘‘green credits’’ for acres of new forest created, which then could be used in view of compensatory of afforestation when new applications are made. The Expert Committee on Coal Sector Reforms has also strongly supported the Working Group suggestion for the possible creation of a market for ‘‘green credits,’’ which could bring in external developers of afforestation projects [23].
Regarding the mitigation of social impacts, the Extractive Industries Review commissioned by the World Bank offers an excellent starting point [61]. This review suggests that activities of extractive industries projects can indeed result in poverty reduction and sustainable development, but this requires three enabling conditions: pro-poor public and corporate governance, including proactive planning and management to maximize poverty alleviation through sustainable development; effective social and environmental policies; and respect for human rights.
The Review notes that it is particularly critical for local communities to receive benefits from extractive industries projects. Some key steps for this are:
· engaging in consent processes with communities and groups directly affected by the projects,
· revenue sharing with local communities,
· systematic monitoring using poverty indicators,
· incorporation of public health components in projects,
· helping build capacity of affected communities, and
· setting up independent grievance mechanisms.
The review also suggests integrated environmental and social impact assessments (instead of disaggregating the two31), planning for closure (especially ensuring funds for appropriate end-of-life activities and helping those who may lose jobs), plans for emergency prevention and response, and addressing the legacies of past. The importance of the last item can not be overstated; it is particularly important in the Indian context, given our history and poor experience with resettlement. For example, the draft rehabilitation policy prepared by the National Advisory Council had a 10-year retrospective [50].
Cernea [58] suggests that the mark of far-sighted management is that it engages in the recognition, rather than denial, of risks. Thus, mining firms must anticipate, identify, and mitigate all reasonable project risks, including those of displaced people. This involves paying particular attention to landlessness, joblessness, homelessness, marginalization, food insecurity, loss of access to common property resources, increased morbidity, and community disarticulation. Reducing and reversing these risks require explicit strategies as well as adequate funds [62].
In the end, successful mitigation of environmental and social impacts requires a concerted effort (a) by government to design and promulgate policies that allow for the development of mines, while at the same time protecting the interests of project-affected people; (b) by mining companies to engage in best mining practices and to take seriously the social responsibility that comes with their operations; and (c) by local citizen groups and NGOs to ensure that they engage positively with the government and the mining companies (although remaining vigilant). Assessing best policies and practices (for improved mining, resettlement and rehabilitation, and conflict resolution) from other countries and adapting them to the Indian context, as needed, should also be helpful.
Fig. 3. Dominance of coal in electricity and viceversa. (a) Generation of electricity by primary sources and (b) trends in coal consumption by various sectors.
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Source: MOSPI 2006 [63] and CEA General Review (various years) [64].
4. Demand-side perspective: coal in power
Since the early 1970s, indigenous coal has primarily fuelled the Indian power sector and, concurrently, most of the coal produced in the country has been used by the power sector (see Fig. 3).32 The use of coal for power generation was accelerated by the creation of National Thermal Power Corporation—a centrally owned public sector corporation that focused on installing of pithead coal power plants to provide additional thermal power to the regional grids. Locating coal-based power at pithead locations was considered optimal as it was more economical to locate power plants near coal mines rather than transporting the coal to power plants located near load centers. Power plant manufacturing capability in the county was also consolidated with the formation of the Bharat Heavy Electricals Limited (BHEL), which began supply indigenously manufactured power plants since 1970; currently, nearly 68% of operating power plant units are manufactured by BHEL.
Electricity generation in the country grew at a high rate in the 1980s, buttressed by a rapid increase in coal-based capacity. The installed capacity of coal power grew at an average annual rate of 8% in the 1970s and at 10% in the 1980s (see Fig. 3a). Consequently, the consumption of coal in the power sector accelerated in the 1980s, and the demand on non-coking thermal coal expanded (Fig. 3b and Fig. 1). In 2004–05, the power sector consumed about 80% of the produced coal and nearly 70% of electricity generation was based on coal.
Broadly, the demand for utility-generated electricity is projected to more than double from about 520 TWh in 2001–02 to about 1300 TWh by 2016–17, with an annual growth rate of about 6–7% [67]; longer term scenarios indicate demand to be around 3600–4500 TWh by 2031–32. The Planning Commission notes that the installed capacity (including captive power) needs to be about 800–1000 GW by 2031–32, depending on GDP growth [10]. This projected rapid growth in electricity generation is expected to be met by using coal, since other resources are uneconomic (as in the case of natural gas, naphtha or LNG),33 have insecure supplies (diesel and imported natural gas and LNG), or simply too complex and expensive to build (nuclear and hydro electricity34) to make significant contribution to the near-to-mid-term growth [5].
Electricity from renewable sources, such as biomass (combustion and gasification), micro-and pico-hydroelectricity, solar photo-voltaics, and urban and industrial waste, are relatively small and used mainly in niche applications.35 Hence, future growth of electricity is dependent on coal for at least the next 30–40 years.
Nearly 50 GW of coal-based capacity is on the shelf of power projects planned for the 11th Plan (2007–2012).36 Based on the Planning Commission scenarios, coal-based capacity of utility power plants is likely to be in the range of 200–400 GW in 2030, up from about 68 GW in 2005 [10]. With the large number of coal-based thermal power plants expected to come online, coal consumption in the power sector is expected to be in the range of 380–500 MT(6–8 quadrillion BTU) by 2011–12 and 1–2 BT (16–31 quadrillion BTU) by 2031–32 [9,10].37
However, as discussed in Section 2.1, there are already concerns about whether domestic production will be able to cope up with the increasing demand for coal, and the domestic production of coal and lignite is projected to be only about 1.4 BT by 2031–32 [10]. Therefore, meeting the expected coal demand would require greater investments in domestic production and also importing greater quantities of coal.
The poor quality of coal (see Section 2.2.3) is another important issue that affects the power sector in several ways. The designs of the coal handling systems, pulverizers, boilers, economizers and electrostatic precipitators (ESPs) have to be altered to account for the high ash and low calorific value of Indian coals. The use of low-quality coal increases auxiliary consumption, operation and maintenance costs and time, and reduces overall efficiency. The high silica and alumina content in Indian coal ash is another problem, as it increases ash resistivity that reduces the collection efficiency of electrostatic precipitators and increases emissions.
The high ash content in Indian coals implies that at least one acre of land is needed for 1 MW of installed capacity [22],38 and hence there are many large power plants with more than 1000 acres of land dedicated simply for ash storage. Over the past decade, 1.4–1.5 million tons of ash was produced annually per GW of installed capacity [72], with the number increasing slightly over time because of increasing ash content in coal and increasing PLF. In order to increase ash utilization, MoEF in 1999 mandated a 100 % utilization of fly ash in a phased manner by 2013–14.39 Fly ash utilization has increased 10-fold from 1992–93 to 2003–04, and about 30% of the generated ash is utilized today. It is expected that by 2010, power plants will plan for 100% utilization of the generated fly ash.
Given these various problems, beneficiation of coal (discussed in Section 2.2.3) is crucial for continued use of domestic coal in the power sector. Although the quality of coal has not affected so far its demand in the power sector, the availability of good quality domestic coal might determine the future power sector coal demand (especially to meet the environmental goals in the power sector).
Notes:
27 For example, posting of such reclamation bonds for mining projects is part of the
28 See: Environment Impact Assessment Notification S.O.60(E); http://envfor.nic.in/legis/eia/so-60(e).html.
29 For example, see: Sunita Dubey, ‘‘EIA: Foundations of Failure ’’(2006), http://www.indiatogether.org/2006/mar/env-eiafail.htm and Sunita Dubey, ‘‘Weakening the enviro- clearance process’’(2004), http://www.indiatogether.org/2004/aug/env-eiaweakn.htm.
30 The Expert Committee, for example, has deemed that it should take less than a year(~11 months) from EIA initiation to EIA approval [23].
31 In contrast, the Expert Committee on Coal Sector Reforms recommended the separation of social issues from the EIA process [23].
32 The impetus for increasing coal usage was the 1970s global oil crises, which made the use of indigenous coal relatively cheaper, forcing the government to emphasize coal usage in many energy-intensive sectors, including electricity generation [65,66].
33 The current relative price of coal and natural gas makes coal the rational choice in most cases except in power plants which are very far away from coal mines. Liquid fuels, such as heavy oils, also have limited use in the power sector for economic and environmental reasons; for example, distillates such as naphtha, high sulphur diesel (HSD), and other condensates are either expensive or too polluting for large-scale use.
34 Despite
35 Even wind power, which has grown significantly in the last decade, is concentrated in a few states where commercial-scale wind resources exist and it contributes only about 0.5% of the total power generation in the country.
36 See: http://cea.nic.in/thermal/Shelf_of_Thermal_Power_Projects_11th%20Plan.pdf; accessed March 23, 2007.
37 In comparison, China (US) coal consumption in power generation for the same period is projected to rise from 16 to 50 (20–30) quadrillion BTU [70].
38 For example, power plants in
39 The MoEF has stipulated that fly ash from power plants be given free (at least until 2010) to brick and cement manufacturers with in 50 km radial distance from power plants; these manufacturers have also been given specific targets for ash utilization [72,73]. See: http://www.envfor.nic.in/legis/hsm/so763(e).pdf.
References:
[60] Ministry of Coal. Report of the working group on coal and lignite for formualtion of 11th five year plan. Ministry of Coal, Editor, Government of
[61] World Bank. Striking a better balance: the extractive industries review.
[62] Cernea MM. The risks and reconstruction model for resettling displaced populations. World Development 1997;25(10):1569–87.
[63] MOSPI. Energy statistics 2006. Ministry of Statistics and Programme Implementation, Editor, 2006.
[64] CEA. All-India electricity statistics: general review 2006. Central Electricity Authority, Editor, 2006.
[65] Chakravarty S. Report of the fuel policy committee,
[66] Pande VG. Towards an increased concern with energy: research and development in
[67] CEA. Sixteenth electric power survey of
[68] CEA. Fourth National Power Plan 1997–2012. Central Electricity Authority, Editor, Government of
[69] Gopalakrishnan A. Indo–US nuclear cooperation: a non-starter? Economic and Political Weekly, 2005.
[70] EIA. International energy outlook 2006.US: Energy Information Agency, Department of Energy; 2006.
[71] Dalal GG. Ash management upstream and downstream—overview. In: Quantification of environmental impacts of large power projects.
[72] CEA. Strategies for ash utilization. Central Electricity Authority, Editor, 2005.
[73] MoEF. Fly ash notification. Ministry of Environment and Forests, Editor, 1999.
to be continued…
Courtesy: Energy Journal (2009), doi:10.1016/j.energy.2008.12.014 reprinted with the permission of the author
NEWS BRIEF
NATIONAL
OIL & GAS
Upstream
LN Mittal may exit Trinidad JV with ONGC
April 7, 2009. The LN Mittal group is planning to exit oil and gas exploration projects it was developing jointly with ONGC in
GSPC strikes gas in KG-21 well
April 6, 2009. GSPC has struck upon a huge gas find in the KG-21 well located on the western side of Deendayal West block in the
ONGC, Reliance explore oil bid tie-up
April 6, 2009. Reliance Industries Ltd and the overseas arm of Oil and Natural Gas Corp will team up to bid for exploration and production blocks in
Chinese, European firms approaches RIL for hiring rig
April 5, 2009. Reliance Industries has been approached by Chinese and European oil majors for hiring one of its drilling rigs, which had also been sought by ONGC. ONGC had been talking to Reliance for past few months to hire DD-KG-1 ultra deep-sea drillship for four years at USD 5,10,000 per day, the same rate at which Reliance had taken the rigs from Transocean Inc of on five-year lease. Though ONGC has been desperately seeking a rig to probe oil and gas leads like the ultra deepsea UD-1 discovery for past two years, the board of the company last week deferred a decision to hire the rig from Reliance on assignment basis. On prodding from the Government and the oil regulator DGH for participating in the 'rig sharing' programme where operators share resources for optimal utilisation, Reliance had agreed to give the DD-KG-1 rig to ONGC. But meanwhile, CNOOC of China and ENI of Italy too approached Reliance offering between USD 560,000 and 570,000 per day for the same rig. ONGC, which needs three ultra deepsea rigs, recently hired a rig from Vantage for USD 585,000 per day but the rig will arrive in December 2010. Another rig it had contracted from Sevan is stuck because bankers financing the rig construction at Korean docks want comfort of a five-year contract instead of three years offered by ONGC and it will not be available before end 2011. The third rig it had tendered for is available for a minimum USD 535,000 dayrate and is available between mid-2010 and end 2010.
OIL, Cairn Energy among 9 companies selected for auction by
April 3, 2009. Oil India Ltd and Cairn Energy are among the nine companies selected by
RIL’s D-6 block output set to redraw country’s energy map
April 3, 2009. The beginning of gas flows from the deep waters of the
RIL to invest $5.9 bn in 9 discoveries in KG-D6 block
April 2, 2009. Reliance Industries has proposed to invest $5.91 bn (about Rs 29,800 crore) in developing nine more discoveries in its prolific eastern offshore KG-D6 block. The development covering 9 satellite discoveries was submitted to the Management Committee (by RIL) in July 2008. The discoveries are proposed to be tied-up with Dhirubhai -1 and -3 finds, which began gas production. RIL and its Canadian partner Niko Resources is investing USD 8.836 bn in producing 80 mcm per day of peak output from Dhirubhai 1 and 3, the first two of the 18 gas discoveries in KG-DWN-98/3 or KG-D6 block. The field development plan (FDP) for the nine satellite discoveries envisages first gas production from the 2.2 tcf of reserves they hold in 2013. RIL has submitted development plan for Dhirubhai 2, 4, 6, 7, 8, 16, 19, 22 and 23 discoveries. Five other discoveries are under appraisal phase, which is typically of about three years duration. Dhirubhai 1 and 3 are estimated to hold 10.03 tcf of reserves and the whole of KG-D6 block about 40 tcf.
HMEL implements SAP solutions to support strategic agenda
April 6, 2009. SAP
HPCL Vizag refinery crosses 9 mt
April 4, 2009. The HPCL Visakha refinery surpassed 9 mtpa for the financial year 2008-09, for the third consecutive year. The refinery achieved 9.15 mtpa, which was 122 per cent of the installed capacity. The fluidised catalyst cracking units of the refinery also surpassed 2 mtpa for the third successive year. The refinery produced 337,000 of bitumen, the highest ever.
The Visakha refinery contributed substantially to the turnover of the
Centre examines Shell’s refinery upgradation contracts
April 4, 2009. The government is examining contracts awarded to Shell Global Solutions for upgrading state-owned refineries without inviting global bids. The move may force the Centre for High Technology (CHT), the technical advisory body of the petroleum ministry, to review its decision of awarding four recent refinery upgradation projects to Shell Global Solutions. The petroleum ministry has instructed government-owned companies not to award any contract on nomination basis. Shell Global started implementing its integrated refinery business improvement programme (IRBIP) on four public sector refineries at
The decision was taken by the then chairman of CHT, who was also the petroleum secretary. Besides the four refinery upgradation projects, in July 2008, CHT also agreed to award four other coastal refinery projects to Shell Global Solutions. They were Haldia refinery of IOC, Mangalore refinery of Mangalore Refinery & Petrochemicals (MRPL) and Mumbai refineries of BPCL and HPCL.
The decision was taken collectively. Based on the approval of their respective boards and clearances, the governing council of CHT approved signing of the contracts between Shell Global Solutions International, the
Transportation / Trade
GAIL, GSPC keen on building KG basin gas pipeline
April 4, 2009. Gail India and GSPC have submitted proposals to build a 1,400 to 1,500 kilometre pipeline connecting the Krishna Godavari basin in the eastern coast to central
The proposals are being evaluated by PNGRB, which would consult the upstream regulator, the Director General of Hydrocarbons (DGH) before giving approvals. The pipeline, which is proposed to be built from Vijaywada in Andhra Pradesh to Bijapur through
It would also enable Gail to strengthen Bijapur as its hub from where it operates the Hazira-Bijapur-Jagdishpur (HBJ) pipeline. This would make transportation of gas from the east coast to north
IOC launches Paradip-Haldia pipeline at higher cost
April 4, 2009. Mr Sarthak Behuria, Chairman of IndianOil, inaugurated the Paradip-Haldia crude oil pipeline system at Paradip. The project included, laying a 330-km long pipeline linking Paradip with Haldia and Barauni Refineries of IndianOil, installation of a Single Point Mooring (SPM) system in the offshore waters of Paradip and a crude oil tank farm consisting of 15 crude oil storage tanks. A near three-year delay in commissioning has escalated the cost of the project by 20 per cent. Scheduled to be completed in March 2006 at an estimated cost of Rs 1178 crore, the project finally started operating beginning December 2008 at Rs 1,420 crore, up by Rs 242 crore. The delay was caused due to a wide range of issues ranging from technological challenges as well as repeated exit of project contractors, especially on the SPM part. According to company sources, the pipeline will transport 11 mt of crude oil a year to refineries at Haldia and Barauni, improving the refining margin of both the refineries by approximately $1 a barrel.
Policy / Performance
Govt. may invite bids for 8 new, 2 recycled coal-bed methane blocks
April 3, 2009.
Govt. receives first installment of profit petroleum from KG basin
April 3, 2009. The government has started receiving its share of profit from Reliance Industries (RIL)-operated D-6 block in the Krishna-Godavari (KG) basin. It has booked $218,960 as its first profit share for the quarter ended December 31, 2008, by selling crude oil produced from the block. The block started producing natural gas recently. The profit was generated from the sale of crude oil produced from the block beginning mid-September at an average price of $50.80 a barrel. In the quarter ended December 31, 2008, RIL earned $21,896,016 by selling crude from MA oil field in KG-D6 block. As per the contract between the government and RIL, the contractor was entitled to keep 90% of the sum towards recovering huge investments made by it in developing the field. The balance amount was distributed between the contractor (RIL) and the owner (the government) in a mutually agreed proportion. RIL has spent $6.26 bn in developing the KG basin block. The government has approved $8.84 bn expenditure to produce 80 mmscmd of natural gas from the block. This also includes creation of an excess infrastructure capacity for producing 120 mmscmd of natural gas from the field. As per a DGH figure, the contractor had spent $4.65 bn for developing oil and gas fields up to March 31, 2008.
GSPC seeks nod to retain Barmer-Sanchor CBM block
April 3, 2009. GSPC has approached the Union Ministry of Petroleum and Natural Gas requesting its permission to retain the Barmer-Sanchor CBM (coal-bed methane) block and include an operating partner in the same. Awarded in CBM-II, GSPC previously held the block with ONGC. The latter had operating interest and decided to relinquish its interests in the block in 2008, after drilling eight core holes and two test wells. According to ONGC sources, the block has CBM reserves of low methane content that too in seams deeper under the earth, making it unviable for commercial recovery. GSPC sources, however, differed with ONGC’s opinion. The Gujarat State PSU recently scouted for possible partners having access to the appropriate technology and capable of recovering the gas on a commercial basis. Three foreign companies from
EGoM meet on April 9 on gas allocation from KG-D6 to power units
April 2, 2009. An Empowered Group of Ministers (EGoM) will meet on April 9 to decide on allocating natural gas from Reliance Industries' eastern offshore KG-D6 fields among power plants. The meeting was to be held last week but had to be postponed after a senior opposition leader complained to the EC that the ministers' panel was going to allocate the gas to power plants in Andhra Pradesh and Maharashtra, giving the ruling Congress party in the two states an advantage for making an election promise of giving free power to farmers. The EGoM meeting has been necessitated with the beginning of natural gas production from the KG-D6 fields. Production is slated to quickly ramp up to 20 mmcmd by next month, creating surplus beyond the about 15 mmcmd allocation made to 15 urea making plants. As per the gas utilisation policy, fertiliser plants have been given the top priority in allocation of the KG-D6 gas. After meeting the entire fuel deficit at urea making units, up to 3 mmcmd gas is to be given to LPG extraction plants. Thereafter, up to 18 mmcmd gas would go to power firms and another 5 mmcmd to city gas projects for retailing CNG to automobiles and piped cooking gas to households.
Fuel pricing policy key to Reliance’s joint venture route for petrol pumps
April 2, 2009. Reliance Industries’ move to rope in an ally and revive operations at its 1,432 fuel outlets (petrol pumps) was not entirely unexpected. After all, substantial investments were made in setting them up and, at the end of the day dealers needed to make money and could not be out of business forever. It has been a little over a year since these pumps were shut down. However, sources in the oil industry wonder how the proposed joint venture model will make any difference from the viewpoint of business viability. RIL recently invited bids from interested parties and, thus far, the only names doing the rounds were Indian Oil Corporation and Shell. IOC, BPCL and HPCL have nearly 35,000 retail outlets between themselves and this network is more than adequate to service fuel requirements of the country. In fact, there is an added worry that sales of petrol and diesel have actually fallen, albeit marginally, over the last few months. As is well known, the three public sector companies get oil bonds from the Government as a means of compensation but this does not apply to private players (or even where there is a public sector stake as in the case of Mangalore Refinery and Petrochemicals, in which the Oil and Natural Gas Corporation has a 72 per cent stake). In fact, this is what prompted RIL to close its outlets in the first place. Hence, even if IOC chooses to team up with RIL in this retail foray, it will have to factor in the risk of sustaining losses should global crude and product prices start to firm up. The joint venture will then either have to choose the option of selling fuel at a discount or just shut shop unless the Government extends the oil bonds facility to this alliance too. If that were to happen, other companies such as Essar, Shell and even MRPL with its smattering of barely a dozen outlets will seek a similar compensation mechanism.
NELP VIII announced on April 9
April 2, 2009. As per the Petroleum Secretary R.S. Pandey, the Government plans to offer 70 oil & gas exploration blocks in the eighth round of auctions starting April 9. The Centre will also offer 10 coal bed methane (CBM) blocks for auction. Out of the 70 oil & gas blocks on offer under NELP VIII, 24 will be deep-water areas, 28 will be shallow-water areas and 18 onland blocks. The auction will be completed after four months. The Government may offer more blocks under phase two of NELP VIII.
POWER
Generation
Reliance Infra likely to increase generation capacity at DTPS
April 6, 2009. Having emerged as the top thermal power station in terms of plant load factor, ADAG Group company Reliance Infrastructure’s Dahanu Thermal Power Station (DTPS) is looking at the possibility of expanding its generation capacity from 500 MW (250 x2) to 1,700 MW. According to officials in the power ministry, Rel-Infra has expressed its intention to expand generation capacity at its DTPS by 1,200 MW and has sounded out the power ministry, Central Electricity Authority (CEA) as well as the
NHPC to develop 10,000 MW projects in NE by 2022
April 6, 2009. To harness the hydel power potential of the North eastern region, state-owned NHPC plans to set up over 10,000 MW capacity projects in the area at an investment of nearly Rs 50,000 crore by the 2022. The total hydel power potential of the country stands at 150,000 MW, and the North-east alone has a potential of nearly 60,000 MW. The government has identified 10,000 MW power capacity to be developed by NHPC. State-run NTPC, which has entered hydel power generation segment would also develop some projects in the region and some would be developed by private power developers. NHPC is developing, Subansiri Lower, the biggest hydro-electric project undertaken in the country so far and is a run of river scheme on river Subansiri near North Lakhimpur on the border of Assam and Arunachal Pradesh.
Damodar
April 5, 2009. Damodar Valley Corporation has initiated discussions with power equipment major BHEL and Coal India Ltd (CIL) to build two super critical thermal power stations as a joint venture. The company also plans to rope in the Rural Electrification Corporation or the Power Finance Corporation as equity partners in the joint venture. As the corporation’s IPO plan was put on the back-burner, DVC was planning to add about 3000 MW generation capacity at Raghunathpur in
The proposal includes setting up two 660 MW units (total 1320 MW) in Kodarma in joint venture with CIL and two 800 MW units (total 1600 MW) at Raghunathpur with BHEL. While CIL’s participation may ensure smooth supply of coal at Kodarma power station, the equity participation at Raghunathpur may offer BHEL the opportunity to commercialise its indigenously developed 800 MW technology. According to the proposal, DVC and its joint venture partner (either BHEL or CIL) will hold 26 per cent each and a consortium of financial institutions led by either REC or PFC will be offered the residual 48 per cent. Both REC and BHEL confirmed some early discussions in regard to the setting up of the Ragunathpur project in joint venture.
NHPC to form JV with Orissa for power projects
April 2, 2009. NHPC would form a joint venture with the Orissa government for setting up power projects in the state. The company would enter into an agreement with the state government for developing power plants and conducting repair and maintenance works for the projects in Orissa. The financial aspects and power sharing modalities will be discussed at a later stage. The company had earlier said, it would commission one of the Teesta hydro-electric projects of 132 MW in West Bengal and 120 MW Sewa-II project in Jammu and Kashmir by December this year, thereby raising its generation capacity by over 250 MW. Its present installed capacity is 5,175 MW. Undeterred by the global economic downturn, the public-sector company is going ahead with its hiring plans. NHPC would recruit nearly 200 people (both technical and executives) in the current financial year (2009-10). NHPC plans a capital expenditure of Rs 28,000 crore during the 11 Five Year Plan (2007-12) and has already tied up funds worth Rs 4,000 crore with state-run Power Finance Corp and nearly Rs 6,500 crore with Life Insurance Corp for funding its power projects.
HCC bags Rs 688 crore hydroelectric project from Bhutan
April 1, 2009. Hindustan Construction Company has bagged Rs 688.06 crore order for package MC3 of 1,200 MW Punatsangchhu-I hydro electric project in
KWF objects to power plant at Gundya
April 1, 2009. Kudremukh Wildlife Foundation (KWF), a Mangalore-based environmentalists’ group, has objected to the comprehensive environmental impact assessment and management plan, prepared by a Bangalore-based institute, for setting up the hydro-electric plant at Gundya.
The Karnataka Power Corporation Ltd (KPCL) has proposed to set up a 200-MW power project at Gundya on the borders of Dakshina Kannada and Hassan districts. In its objection filed before the Deputy Commissioner of Dakshina Kannada during a public hearing on the project conducted at Gundya recently, the foundation alleged that the report contained false and misleading information and data. It urged the Deputy Commissioner, who was the presiding officer for the public hearing, to reject the report. The report had mentioned that the project site was at a distance of 30 km from Pushpagiri Wlidlife Santuary. But, according to the topographic map prepared by the Survey of India, the proposed project site was within 9.5 km of the sanctuary and within the ecologically sensitive zone, as per the Environment (Protection) Act.
Transmission / Distribution / Trade
Load-shedding could have been withdrawn earlier
April 6, 2009. According to Kerala Electricity Employees Confederation general secretary, though the government could have withdrawn load-shedding two months ago, it is planning to do so just before the election date to garner votes. The KSEB authorities had informed the government earlier that load-shedding could be withdrawn. The LDF government should apologise for the delay in withdrawing the load-shedding. If load-shedding could be withdrawn during summer, when consumption was at its peak, the government could well have done the same earlier. When load-shedding was withdrawn during the days of SSLC examination, and later resumed, there was no difference in electricity consumption. He charged the government with being most inefficient in handling matters concerning electricity. Even though dams were full, water could not be utilised. The Panniyar hydel project has remained shut since September 2007. One and a half years has lapsed after the government declared that the project would be opened in six months.
Karnataka power consumption touches 139.94 MUs
April 4, 2009. It is not just the political heat which is increasing in Karnataka due to the Lok Sabha elections but also the power consumption which has touched a record high this summer. The State’s daily power consumption touched 139.94 MUs. This is the first time that power consumption in Karnataka has touched such a high level.
The consumption level is further expected to increase on April 3. What has caused concern among the power utilities is that power consumption is constantly increasing by nearly one million units a day in the last few days. The indication is that the daily consumption might even touch 145 MUs some time this month. The increase in consumption is being attributed mainly to the summer heat which has forced people to use air-conditioners and fans and also operation of irrigation pumpsets by farmers to protect their standing summer crops.
BHEL to form JV for transmission equipment
April 2, 2009. BHEL is planning to invest Rs12bn in setting up a joint venture with an international firm for manufacturing transmission equipment by June this year. The company is in talks with French equipment maker Areva and
India offers to export electricity to
April 2, 2009. India has offered to export electricity to neighboring
Four new power consumers may get RIL's KG gas
April 6, 2009. The government plans to restructure the priority list of power plants awaiting natural gas supply from Reliance Industries’ (RIL) D-6 block in Krishna-Godavari basin, taking into account various factors such as higher demand for power from
Nigerian LNG plan turns out all gas for NTPC
April 6, 2009. Efforts of
The PSU had also offered to renovate a 200 MW unit at a 1,320 MW plant and train around 30 Nigerian engineers and set up a training institute in the country. The gas from
L&T bags Rs 1,245-cr
April 1, 2009. Larsen & Toubro has bagged a Rs 1,245 contract for the construction of the dam package, a part of the 1,200 MW Punatsangchhu-I Hydroelectric Project in
The scope of work involves construction of the diversion tunnel, dam, intake and desilting arrangement including hydro-mechanical works. L&T won the order through a competitive bidding process. WAPCOS is the engineering and design consultant of the project. This is the first of a series of 10 hydropower projects jointly identified by the Governments of
NTPC to add 217 bn units of electricity in FY10
April 1, 2009. NTPC has signed a MOU with the Union Power Secretary, Government of India for generating 217 billion units of electricity during the financial year 2009-10. The MOU includes targets of important milestones relating to project completion schedule of ongoing power projects, coal mining activities, Total Quality Management, Human Resources Development, Business Development Activities, including activities of Distributed Generation, R&R, ERP, R&D, Ash Utilisation and Environment measures and also the targets in respect of subsidiaries of the company i.e. NVVN, NESCL, NHL and Kanti Bijlee Utpadan Nigam Ltd. The company has also announced that its installed capacity crossed 30,000 MW after commissioning a 250 MW unit. The utility’s group capacity now stands at 30,144 MW.
INTERNATIONAL
OIL & GAS
Upstream
Petrobras confirms new oil, gas field in Santos Basin
April 7, 2009. The consortium formed by Petrobras (63%, operator) and Repsol (37%) has delivered a Declaration of Commercial Viability for a light oil and gas discovery made in reservoirs located above the salt layer in block BM-S-7, located in the Santos Basin. This discovery was announced after the completion of well 6-BRSA-661-SPS (6-SPS-53), on January 26, 2009. The new field, Piracuca, is located off the coast of the State of Sao Paulo, some 200 kilometers from the city of
China's largest oil field to Maintain crude output
April 7, 2009. China's largest oilfield Daqing aims to produce 40 mt of crude in the next 10 years. Currently in the
Daewoo International extends gas exploration in
April 3, 2009. Daewoo International Corp. has decided to extend the exploration of a gas block off
Downstream
NIOC to participate in Malaysia, Indonesia,
April 7, 2009. The National Iranian Oil Refining and Distribution Company is taking part in joint projects to construct refineries in
Pakistan's Bosicor to invest $500 mn on refinery, oil storage, petchem
April 6, 2009. Bosicor Pakistan Limited is to invest US$500 mn in the oil industry over the next two years as part of its expansion plans to be the leading market player in
Jordan, Swiss banks reach initial refinery deal
April 6, 2009. The Jordan Petroleum Refinery Co (JPRC) has signed a preliminary memorandum of understanding with a consortium of 12 Swiss banks that allow them to acquire a 51-percent stake in the sole Jordanian downstream facility. The agreement, provides for a strategic partnership that involves the spending of about $1.5bn by the Swiss banks for financing the JPRC's fourth expansion.
Vietinbank provides $200 mn loan for oil refinery
April 6, 2009. The Vietnam Bank for Industry and Trade (Vietinbank) and the Vietnam National Oil and Gas Group (PetroVietnam) signed a credit contract of US$200 mn on April 3 for the Dung Quat Oil Refinery project. The contract is part of PetroVietnam's long-term capital arrangement plan for the 2009-2013 period. Among the total investment capital of US$3 bn for the Dung Quat project, the Bank for Investment and Development of Vietnam (BIDV) provided US$1 bn in preferential loans and several commercial banks came up with an additional US$250 mn through the Bank for Foreign Trade of Vietnam (Vietcombank). After four years of construction, the Quang Ngai-based oil refinery turned out its first batch of distilled oil in February and will hit its full capacity of 6.5 mt in August this year. This year, the plant is expected to turn out 2.6 mt of a variety of petrol products, meeting around 30 percent of domestic demand.
PetroChina refined 40,000 tons of Sudanese crude in March
April 2, 2009. Dalian Petrochemical of PetroChina processed 40,000 tons of high-acid crude oil imported from
The successful introduction of high-acid crude paved the way for upcoming large-scale processing of such crude. PetroChina is building a 10 mtpa refinery in South China's Guangxi Zhuang Autonomous Region, which is designed to process high-acid crude oil from
The restructuring and expansion project of PetroChina's Jilin Petrochemical's 10 mtpa refinery has been started with catalyzing and cracking facility to be in place in the mid of 2010.
CNOOC to expand Huizhou refinery
April 1, 2009. CNOOC, the leading offshore oil producer in
The oil firm plans to expand the capacity to 20 mt after its phase II project is completed. Phase I project of the Huizhou Refinery cost 19.3 bn yuan. Lagging behind Sinopec and PetroChina in refining, CNOOC is expected to allocate part of its huge investment to expand its refining sector. CNOOC is the parent company of CNOOC Ltd.
Transportation / Trade
Russian oil pipeline to reach Chinese border within weeks
April 6, 2009. The Russian state oil pipeline Transneft will finish the laying of the East Siberia-Pacific Ocean (ESPO) oil pipeline to the Chinese border within weeks. In just a few weeks, the phase during which the pipeline will reach the Chinese border will be over and it will go further to the
Russia and
Murkowski introduces bill for in-state
April 6, 2009. U.S. Sen. Lisa Murkowski, R-Alaska introduced legislation designed to help development of an in-state natural gas pipeline in
NEB rejects Enbridge tools and tariffs application
April 2, 2009. The National Energy Board (NEB) denied an application from Enbridge Pipelines Inc. (Enbridge) for the toll principles as found in its Transportation Service Agreement and the resulting tolls to be charged for transportation services on its only westbound Canadian crude pipeline. Enbridge's 849 km-long Line 9 pipeline, which began westbound service in 1999, can ship up to 38,160 cubic meters (240,000 barrels) of crude oil per day from
PetroChina to invest in another Shaanxi-Beijing pipeline
April 1, 2009. PetroChina Natural Gas Pipeline Company, a joint venture between PetroChina and Beijing Gas, has decided to invest 20 bn yuan in laying the third Shaanxi-Beijing gas pipeline. PetroChina, having a 60 percent stake in the joint venture, would invest 12 bn yuan in pipeline construction. The pipeline is scheduled to come on stream in the second half of 2011 and is expected to provide
Policy / Performance
Iraq,
April 7, 2009.
Cheetah O&G acquires
April 7, 2009. On April 3, Cheetah Oil & Gas agreed to purchase producing Oil & Gas Assets in the State of
Qatar oil minister: Barzan project with Exxon delayed, not shelved
April 6, 2009. According to Qatar Oil Minister, country has delayed, not shelved, the large-scale Barzan natural gas field project to be developed with Exxon Mobil Corp. (XOM) to benefit from a drop in construction cost. It was due to costs because the price trend (of construction) has changed since 2008. According to him the strategic decision would ensure that
ABB aces installation contract for El Merk project in Algeria
April 2, 2009. ABB has won a contract for about $490 million as part of the El Merk oil and gas project in
The project consists primarily of design and installation of pipelines, field gathering stations, gas distribution manifolds and flowlines/trunklines, as well as water and gas re-injection facilities. The pipeline network will connect oil and gas wells to the processing plant via 10 gathering stations. Facilities to inject gas and water into the wells will help increase their output.
POWER
Power generation rises to 2900 MW in Nigeria
April 7, 2009. According to the Power Holding Company of Nigeria (PHCN), power generation has risen to 2,900 MW after dropping by 700 MW due to vandalism of the gas pipeline of the Nigerian Gas Company last week. The increase was due to the resumption of gas supply from the Otorogu Gas station in Delta. Power supply would soon be stable when all the power stations embarked upon by the government were completed. The attainment of the 6000 MW generation capacity by December 2009 is not negotiable but achievable.
Nepali private entrepreneurs to start rural hydropower projects
April 6, 2009. The Federation of Nepal Chambers of Commerce and Industry (FNCCI) will start rural hydropower projects in 45 districts. The umbrella organization of Nepali private entrepreneurs is taking this step after
Nepal is suffering an acute shortage of electricity these days and micro-hydropower can be a solution. The present power cuts stretch to 16 hours a day. Earlier, FNCCI and Association of District Development Committee Nepal (ACCDN) had designed a micro-hydropower project in the rural areas to end load shedding.
According to the website, FNCCI along with ACCDN had planned to start 1 MW to 5 MW capacity projects in 45 districts using local funding. The project aims to mobilize local finance and provide electricity to nearly 300 village development committees.
Transmission / Distribution / Trade
NOPEC offers discounted electricity
April 6, 2009. The major electric-buying aggregation in
Newfoundland touts historic hydro deal with
April 2, 2009. For the first time,
Skills gap puts new nuclear plants at risk
April 7, 2009. The government has been warned that an engineering skills shortage could hit plans to build new nuclear power plants. A report has claimed a gap in the civil service could impact on a new generation of atomic stations in which west
PSC denies utilities’ rate hike requests in New York
April 7, 2009. The state Public Service Commission dismissed $278 mn rate hike requests by two utilities that would have raised the average residential electric bill by $21 a month. The five-member PSC board voted unanimously to support the recommendation of the Department of Public Service staff, which was to deny the increase proposed by New York State Electric & Gas and Rochester Gas & Electric. If approved, the increase would have taken effect in July. NYSEG has 45,000 local customers. RG&E serves only the
Kazakhstan offers to set up nuclear bank
April 6, 2009.
The fuel bank would produce enriched uranium, which is a necessary ingredient in nuclear power reactors, keeping stocks of it for sale. Countries that are building nuclear reactors would not have to make their own uranium fuel - they could simply buy it from the bank. It would be supervised IAEA, which inspects reactors.
Electricity theft on the rise in
April 4, 2009. Consumer advocates in
Yar'Adua promises improved electricity in eight months in Nigeria
April 3, 2009. Nigeria President has assured Nigerians that there would be substantial improvement in power supply in the country in the next eight months. According to the president, for the first time in several years, government appropriation had been tailored to meet specific goals as ministries had been given targets to deliver by the end of the year. The President who was represented by the Minister of State for Information, Alhaji Ikra Aliyu Bilbis expressed the hope that by the end of the year, Nigerians would begin to enjoy a measure of stable electricity. Country’s strategy is to place priority on those sectors that will facilitate the resuscitation of the economy and bring immediate relief to the vast majority of our people.
Renewable Energy Trends
National
HC orders notice on hydel projects
April 7, 2009. The High Court has ordered notice to the Union Government and other departments over projects planned in
CERC to ensure deficit states too get feel of green power
April 7, 2009. Moving in to make states comply with an existing rule to have a certain portion of their power grid reserved for green energy, the government is planning to set up a renewable power exchange that would issue certificates to surplus states which can be sold to deficit states looking to fill their mandatory quota. The Central Electricity Regulatory Commission (CERC), under the ministry of power, will soon set up an independent body to enable registry of renewable power trading between states, which could facilitate issuance of renewable energy certificates to states with surplus green energy. These could then be sold to deficient states to help them meet the mandatory requirement of sourcing a minimum prescribed proportion of the total power supplied by them to the grid from renewable sources. For instance, if Tamil Nadu has surplus power generated from wind energy, it can sell the surplus power through such certificates to states like
In this way,
The move will ensure that renewable energy initiative of several states will no longer be optional. Even as the Electricity Act, 2003 makes it mandatory for states to promote use of renewable energy and source a certain quantum of green power for their grids, so far only 15 states have set quotas for renewable power.
While the government is planning to enact a new renewable energy law that would stipulate mandatory use of a certain quantum of renewable energy in each state, issuing renewable energy certificates would facilitate a larger number of states to use green energy as part of their power supply.
The gross installed capacity of grid interactive renewable power in the country is estimated at 11,273 MW, which accounts for 8% of the country’s installed generation capacity. While the government plans to install additional 78,577 MW of power-generation capacity by the end of 11th Five-Year Plan, it has set a target of 13,500 MW for renewable energy sources.
PTC India sanctions Rs 721 crore to power sector during 2008-09
April 6, 2009. PTC India Financial Services Limited (PFSL) set up by PTC India Limited, a major player in power trading, as its strategic investment arm has sanctioned financial assistant of Rs 721 crore to power sector projects during 2008-09. This assistance has been in the form of equity and/or debt to 15 projects both in renewable and non-renewable areas. Starting its functioning in middle of 2007-08, PFSL has so far sanctioned financial assistance of Rs. 876 crore to 20 projects till 31st March, 2009. PFSL has also been promoter of first ever Power Exchange, namely, Indian Energy Exchange (IEX) and has also set up joint ventures for promoting power projects based on biomass, wind and solar. The assistance from PFSL made so far would help supporting capacity creation of 4684 MW.
India-Nepal joint venture to tap wind energy
April 4, 2009. An Indian company and a Nepali firm have recently formed a joint venture company USP Wind and Power System in
Global
Japan loses No. 2 spot to
April 7, 2009. Japan has slipped from the No. 2 position in the world in grid-connected solar photovoltaic capacity, replaced by
China targets 20 bn watts of wind power capacity by 2010
April 7, 2009.
Vestas to supply wind turbines in
April 7, 2009. Danish wind turbine manufacturer Vestas Wind Systems said that it has received an order for a total of 76 units of the V90-3MW turbine for two projects in
SunEdison passes milestone in solar generation
April 6, 2009. SunEdison, the largest solar energy services provider in North America, has now delivered more than 100 gigawatt-hours of electricity from photovoltaics, making it the first owner-operator in the
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