Energy News Monitor |Volume V, Issue 30

Impact of Power Sector on Social and Environmental Issues: Remedies

Shankar Sharma, Consultant to Electricity Industry

Synopsis

ndian Institute of Science (IISc), Bangalore is celebrating its Centenary year during 2008-09. As a part of these celebrations a symposium “Lake 2008” was conducted between 22 Dec - 24 Dec 2008 at Bangalore focusing on water bodies. This article is based on a presentation made by the author in this symposium.

Power sector has the potential to become the biggest polluter of environment, if not managed carefully. It also can impact the society in many other ways. An objective review of the electric power sector in our country and of the various energy options available to us will reveal that it is techno-economically feasible to meet the legitimate demand for electricity without having to compromise on environmental and social aspects. The results of a pilot study undertaken on Karnataka clearly demonstrate this conclusion.

1.  INTRODUCTION

Electricity, as a form of convenient and widely used energy system, is posing many challenges as far as its impact on environment and natural resources are concerned. In the light of the fact that about 22% of all GHG emissions and about 42% of all CO2 emissions at global level are being associated with electric power generation activities, electricity industry has the potential to become the biggest polluter of our environment and the fastest exploiter of the natural resources, if not managed responsibly. Whether it involves mining of coal or nuclear fuels, or power plants, or damming of rivers, or huge transmission lines or wind mills etc. till it is used, electricity has huge impact not only on the environmental aspects, but also on the social and economic aspects of the society. In view of the ever increasing concerns of Global Warming on the human race, there is a dire need for the society to take a holistic look of all aspects of our society impacted by power sector urgently in meeting the legitimate electricity demand without compromising on the all critical environment. 

Though electricity is considered to be essential for the socio-economic development of the society, many aspects of the power sector have resulted in adverse impact on sections of the society. Whether it is mining of the fossil fuels or nuclear material, whether it is the construction of large dams and power stations or extensive network of transmission lines, large number of people have been displaced with disastrous consequences. Health issues associated with power production alone is a major issue to contend with. Only with extreme caution and responsible approach these issues can be managed with minimum impact on the society.

An objective review of the electric power sector in our country and of the various energy options available to us will reveal that it is techno-economically feasible to meet the legitimate demand for electricity of all sections of our society on a sustainable basis without having to compromise on environmental and social aspects. But what is needed is a paradigm shift in the very way our society views the apparent demand for energy, and a holistic look at all needs of the society. To substantiate this argument a case study of Karnataka power system is considered as an example.

2.  THE POWER SECTOR CRISES

Whereas the availability of adequate quality and quantity of electricity is considered to be essential for the development of every community around the world, a close link has also been recognized between the consumption of electricity and the affluence. For India, where more than 50% of its huge and growing population is either yet to get access for electricity infrastructure or is yet to fully realize its electricity demand potential, it is a serious challenge to supply adequate quality electricity to all sections of the society while minimizing the adverse impact on social and environmental aspects.

Since independence huge sums of money have been spent in developing electricity infrastructure. The total installed capacity in the country has increased by few hundred times to about 135,000 MW now. For this purpose large chunks of forest and agricultural lands have been diverted, tremendous quantities of fresh water have been dedicated, millions of people have been displaced from their natural habitats and great amounts of pollutants have been added to the environment. But the electricity demand of the large sections of the society is still unmet, which makes it essential to review our past policies.

The conventional sources of electricity such as coal, diesel and gas are fast running out, while nuclear power sources have huge concerns of their own in the form of political, technological, environmental uncertainties. The dam based electricity source, which appears to be a renewable source, has its own environmental and social concerns. While there have been claims of large reserve of coal in the country, in recent days the Planning Commission has projected the economically extractable coal reserve to last for only about 40 years at the ever increasing levels of extraction. Whereas the country was never self sufficient in petroleum products, its import is expected to reach 85% of the total consumption by 2020. Due to economic and technical reasons alone the country cannot hope to achieve the energy security, if the business as usual policy of relying on conventional technology generating sources is to be continued.

to be continued…

Views are those of the author                      

The Nuclear Illusion (part – X)

AMORY B. LOVINS AND IMRAN SHEIKH

 

Continued from Volume V, Issue No. 29…

 

lobal industry and government data compiled annually by Rocky Mountain Institute¹¹⁴ show that micropower surpassed nuclear power in 2006 in total electricity production (each provides one-sixth of the world’s power), surpassed nuclear generating capacity in 2002, and is growing enormously faster.

In 2005, global micropower provided one-fourth of the world’s new electricity: it added 10–14× (without or with peaking and standby units) as much capacity and 3× as much output as global nuclear added in the same year.

In 2006, nuclear lost 0.2% or 0.75 GW of net capacity as retirements exceeded new units, offset this loss by 2.2 GW of upratings for a 1.44-GW net gain, and raised its output 1.3% through the upratings plus higher capacity factors.¹¹⁵ Yet in 2006, micropower added 43.4 GW, or 57.7 GW including peaking and standby units that can generally be made dispatchable (able to send out power reliably whenever desired).

During 2007, for which cogeneration data are not yet available, we estimate that distributed renewables added another ~30 GW to achieve ~222 GW of total capacity¹¹⁶ (60% as much as nuclear), and they are expanding by ~15% a year¹¹⁷ while nuclear power struggles to expand at all.

Figs. 6 and 7 compare the historic and industry-forecast global evolution of nuclear power (heavy black line) and of micropower so far in the 21^st Century, when nuclear power has remained stagnant while micropower has burgeoned:

Fig. 6 (top): generating capacity of distributed electric generation worldwide

and Fig. 7: its electrical output; data are actual through 2006 or 2007 depending on data set, then industry- projected. Neither graph shows decentralized peaking nor standby generators, which have added large amounts of capacity since data collection began in 2000 (Fig. 8 below); also, some kinds of cogenerators in some countries are not yet included. By the end of 2006, micropower had 32% more capacity, and distributed renewables had more than half as much capacity, as nuclear power did, and together, both kinds of micropower generated 5.8% more electricity than nuclear power did.

Dismissed as unimportant, uneconomic, unreliable, and futuristic, micropower in 2005 provided from one-sixth to more than half of all electricity in a dozen industrial countries,¹¹⁸ including 53% in Denmark, 38% in Finland and Holland, ~31% in Russia, 20% in Germany, 17% in Japan and Poland, vs. ~6%¹¹⁹ in the United States, which still has many barriers to fair competition.¹²⁰ Meeting the large total needs of a modern society for electrical services requires a lot of electricity, or less electricity used more productively, or some combination. But the total scale of the electricity enterprise has been widely confused with the size of its parts. The first objection commonly raised to micropower and negawatts is that their small individual scale somehow makes them insufficient collectively. Yet like total electricity demand that is the sum of many mainly small loads, the sum of many small generators’ output can be enormous. The same revolution that has often replaced computer centers with networked PCs and central telephone exchanges with distributed packet-switching is already starting to transform the electricity industry. The word “baseload” is often misused to describe the power plants that big economies supposedly need. But in utility load-dispatch parlance, “baseload” doesn’t mean big, steadily operating, or dispatchable; it means plants that generate electricity at the lowest operating cost, so they’re dispatched whenever available, supplemented as needed by costlier-to-run plants. (Thus any renewable generator is run as a baseload resource because it has almost no operating cost. Its capital cost which must be paid whether it runs or not is irrelevant to this calculus). As explained below, no sensible criterion requires a given power plant to be big nor to run steadily, since many small plants, even variable ones, can add up to big and reliable supply—as they increasingly do in competitive power systems that allow them. For their first century of the electricity industry, power plants were costlier and less reliable than the grid, so it made sense to build bigger plants that backed each other up via the grid. But in the latest quarter-century, power plants have become cheaper and more reliable than the grid, so cheap and reliable power must now be made at or near customers. This can create many hidden economic benefits—not counted in the comparisons in this paper—that typically raise distributed resources’ economic value by roughly a game-changing tenfold.¹²¹ Markets are starting to recognize and capture these “distributed benefits,” such as reduced financial risk from small and fast rather than big and slow increments of capacity, fuel-price hedging by renewables (which have no fuel and hence no fuel-price volatility), avoided grid costs and losses, and better avoidance and handling of faults on the grid. Utility planners are also starting to realize that, as the late Dr. Shimon Awerbuch showed at the International Energy Agency, a balanced portfolio of electrical sources should include a substantial fraction—typically tens of percent—of renewables, even if they cost more, for the same reason and with the same mathematics that a financial portfolio should include riskless Treasuries even of they cost less: renewables’ constant price improves the price/risk profile of the entire portfolio. Moreover, negawatts, though less carefully measured, seem to add each year about as much effective new “capacity” as micropower does worldwide.¹²² Thus probably more than half of the world’s new electrical services now come from negawatts and micropower, while all central plants—big thermal stations plus big hydro—provide probably less than half.¹²³ The electricity revolution is already well underway and is rapidly accelerating.

Which power sources are fastest to deploy?

Nuclear power is often claimed to be the only power source that can be deployed quickly enough to deal with urgent issues like climate change. For it to displace much coal-fired power would require an immensely larger nuclear industry:¹²⁴ in perhaps the most ambitious vision, John Ritch, director-general of the World Nuclear Association, envisages¹²⁵ a 20× nuclear expansion by 2100, starting with more than 1,000 reactors in the next 25 years and 2,000 to 3,000 by 2050 (vs. ~440 today, most or all of which will have retired by about 2050). Yet during 2004–07, global nuclear installations averaged just 1.5 GW/y, or about one big plant’s worth per year, including upratings of older plants, while the world added ~135 GW/y of total generating capacity. Nuclear power had only a ~2% share of global growth in electric generating capacity, while windpower (13.7 GW/y) had 10%, all distributed renewables 17%, and all micropower 28% (probably rising to around one-third in 2007–08). These empirical data contradict the claim that nuclear is fast and big while its non-central-thermal-plant alternatives are small and slow. On the contrary, during 2004–07, micropower added ~14× more capacity (~20× in actual installations without upratings of old nuclear plants) and ~3× more electrical output than nuclear, and is pulling away. The nuclear industry projects that its gross additions (excluding retirements and upratings) will total 17 GW during the five years 2006–2010, but micropower is now adding 17 GW about every 15 weeks—17× faster.¹²⁶ Of course, the nuclear industry hopes for a giant turnaround. But this supposedly irresistible force is colliding with a nearly immoveable object: the existing nuclear fleet was mostly built in the 1970s and 1980s, so its demographics entail retirements at an increasing pace. If operating lives remain the normal 40 years (32 by law in Germany), the industry must exceed any plausible global construction rate just to replace retiring plants, which would otherwise be all gone by 2050.¹²⁷ Further life extensions, which the United States and some other authorities are routinely allowing (though increasing doubts are being raised about their soundness),¹²⁸ could postpone but not eliminate this problem. It also remains to be seen whether plants older than their operators have high enough uptime and low enough repair costs to justify their continued long-term operation against ever-stiffer competition from rapidly evolving rivals. Even neglecting retirements, it’s hard to imagine how even the most vigorous nuclear revival could catch up with competitors’ momentum shown in Figs. 6–7 (plus a roughly comparable if not larger contribution by negawatts not shown in those graphs). This is not just because the competitors are winning so decisively; it’s also because of fundamental market dynamics: many small, short-lead-time units accessible to numerous market actors, and selling like PCs or cellphones, can empirically add capacity faster than a few big, long-lead-time units that need specialized institutions and are built more like cathedrals. Nuclear growth has indeed been overtaken by some of the technologies claimed to be least able to do so—even, ignominiously, by the costliest one, photovoltaics (solar cells). In 2006 worldwide, nuclear power added less net capacity (1.44 GW) than photovoltaics added (1.74 GW), or one-tenth as much as windpower added (15.1 GW). In 2007, nuclear capacity added or uprated by 2.5 GW of net capacity according to the IAEA or 3.2 GW according to the World Nuclear Association,¹²⁹ while windpower alone added ~20.6 GW, including 5.2 GW in the United States,¹³⁰ 3.5 GW in Spain (now one-tenth wind-powered), and 3.2 GW in China.¹³¹ Thus each of those three countries in 2007, and Spain alone in the past few years, added more windpower capacity than the world added net nuclear capacity. By spring 2008, global installed windpower capacity had exceeded the United States’ 100 GW of installed nuclear capacity.¹³² To be sure, per kW of capacity, a typical well-performing nuclear plant¹³³ produces ~2× the electric output of excellent or ~3× that of typical windpower, or ~4× that of typical solar photovoltaics, so windpower is adding electrical output only about 2–3 times faster than nuclear power. But because cogeneration and many renewables (such as geothermal, small hydro, biomass/ waste-fueled generation, and solar-thermal-electric with thermal storage) produce power quite steadily, micropower as a whole has about a capacity factor of about 0.65, three-fourths of nuclear’s in the United States (or a higher fraction worldwide, since most countries’ nuclear plants have lower capacities than U.S. ones now do). Moreover, micropower’s output is soaring while nuclear’s lesser output has nearly flatlined (Fig. 7) as its capacity stalls out. For example, the European Union during 2000–07 installed 158 GW of generating capacity (excluding some distributed resources): 88 GW gas, 47 GW wind, 9.6 GW coal, 4.2 GW oil, 3.1 GW hydro, 1.7 GW biomass, and 1.2 GW nuclear. In 2007 alone, wind added 8.5 GW to Europe’s net capacity (40% of the total, exceeding gas’s 8.2 GW); coal lost 0.8 GW and nuclear lost 1.2 GW.¹³⁴ In 2007, the United States added more wind capacity than it had added coal capacity in the past five years combined. Such market success is sometimes dismissed as an artifact of subsidy. That may be partly true in Germany, which pays high “feed-in” prices for renewables that sell power to the grid— probably above any historic German nuclear subsidies but below Germany’s big coal subsidies. ¹³⁵ But the broad claim doesn’t stand up to scrutiny. Such support is generally being phased down in Germany and in a few other countries that have used limited pump-priming variants of this system. In Spain, and in Japan (which generously subsidized early photovoltaic installations to build the #1 world PV industry), the decline is generally even faster. The United States sporadically gives windpower an inflation-adjusted Production Tax Credit with a levelized value of 0.94¢/kWh in 2007 $, but has interrupted it several times, each time crashing the nascent domestic windpower industry,¹³⁶ which therefore provides only about half of U.S.-installed turbines. Similarly misguided policies have cut U.S. photovoltaic makers’ share of their domestic market from over half to ~8%. But robust growth in renewables continues to accelerate after, and in many countries without, significant subsidies. Nearly all subsidies to renewables, where present, are far smaller than historic or current nuclear subsidies. And neither cogeneration nor efficient end-use receives or has received subsidies of any consequence almost anywhere. A simpler and more plausible explanation for distributed resources’ competitive success against nuclear power, and other central stations, is thus that they have lower costs and financial risks, as discussed above.

To illustrate how David is beating Goliath, Fig. 8, which underlies Figs. 6 and 7, compares the actual and industry-projected profiles of capacity additions by each distributed generation technology with that of nuclear power (including a thin orange dotted line for its construction starts, a leading indicator). The heavy “total” lines show that micropower’s net capacity additions have lately been an order of magnitude bigger than nuclear’s, and that this gap is widening. Indeed, U.S. Energy Information Administration data, which have a four-year reporting lag, show that during 2001–04, the global rate of ordering fossil-fueled power plants declined by approximately 20 GW, presumably displaced by micropower and negawatts.

Fig. 8: Relative annual global capacity additions by nuclear power (red) vs. its main distributed generation competitors, whose 44–58-GW combined effect in 2006 (depending on whether standby and peaking fossil-fueled units are included) is the sum of their individual curves. The orange dotted line is nuclear construction starts—a leading indicator—whose history suggests that the 2010 jump in nuclear completions is probably optimistic. The thin aqua cogeneration line excludes, and the thin purple line above it includes, an additional 14 GW of peaking and standby units, most of which could be made dispatchable if desired; those units weren’t reported before 2000. All capacity changes shown are net of reported additions, retirements, and up- and downratings, though nuclear upratings are not clearly reported. Electrical savings (negawatts) aren’t shown in this graph, but their capacity effect probably rivals and may exceed that of distributed- resource additions.

Notes:

114 This documented database, now including 2006 updates, is at www.rmi.org/sitepages/pid256.php#E05-04. It is consistent with the authoritative Renewables Global Status Report: 2006 Update and its www.ren21.net database, independently derived by a global expert network; that database shows slightly larger totals because it counts small hydro units up to 50 MW in China and 30 in India, vs. our 10-MW limit worldwide.

115 According to the International Atomic Energy Agency’s PRIS database and data kindly provided by IAEA, excluding two units that are in long-term shutdown.

116 Using our more restrictive 10-MW small-hydro limit; REN21 estimates ~240 GW using its broader limits (50

MW in China, 30 MW in Brazil).

117 Excluding ~780 GW of big hydropower: Renewables 2007 Global Status Report, www.ren21.net/pdf/RE2007_Global_Status_Report.pdf, 2008.

118 World Alliance for Decentralized Energy (WADE), World Survey of Decentralized Energy 2006, May 2006, p.

31, www.localpower.org. WADE uses a narrower definition of distributed resources than this paper does. At least two more countries appear to qualify based on distributed resources that WADE’s survey omits—wind farms, central PV, small hydro, geothermal, solar-thermal-electric, and biomass/waste-fueled generation. However, even as defined, WADE’s figures are conservative because they omit <0.5-MWe thermal systems and all steam-turbine cogeneration outside India and China—a significant omission because backpressure turbines are popular in Europe. Steam turbines were not included in the analysis for this paper.

119 Possibly more if, as claimed at http://uschpa.org/images/RoadmapSep03_77GW.jpg, installed U.S. cogeneration capacity is about twice what USEIA reports.

120 A.B. Lovins et al., Small Is Profitable, RMI (2002, an Economist book of the year), www.smallisprofitable.org, documents 207 such “distributed benefits.” Despite these barriers, a recent Sierra Energy Group survey found that of 150 U.S. utilities surveyed, 80% of investor-owned, 70% of municipal, and ~50% of cooperatives already used one or more forms of distributed generation.

121 Id. Note that this comparison refers to value, not cost or price.

122 As a rough indication, the 6.7% (1.73%/y compounded) drop in U.S. electrical intensity (total electricity end-use consumption per real dollar of GDP, per USEIA, Monthly Energy Review, Mar 2008, without weather adjustment) during the four years 2002–06, whatever its causes, would correspond at constant load factor to saving 49 GWp in 2006 or ~12 GWp/y. The United States uses only one-fourth of the world’s electricity, and much of the world has comparably or more vigorous intensity-reducing efforts, so it’s hard to imagine that global savings, perhaps on the order of four times U.S. savings or ~50 GW/y, don’t rival or exceed global additions of distributed generating capacity, which, excluding/including peaking and standby units, totaled ~124/168 GW during the four years 2002–06 (comparing year-end figures), or an average of ~31/42 GW/y. Thus the total effect of negawatts plus micropower may average on the order of 100 GW/y as of a few years ago, or substantially more today.

123 The latest (7 Sept 2007) USEIA data (www.eia.doe.gov/pub/international/iealf/table64.xls) show that 2002–05 world physical additions of generating capacity averaged 120 GW/y. Adding the negawatt effects in the previous note would imply annual electrical-service-capacity additions averaging ~214 GW/y, of which ~94 GW/y would come from micropower and negawatts—nearly half on 2002–06 average, half or more nowadays (annual micropower additions nearly doubled during 2002–06). It’s unclear how much micropower EIA’s totals include.

124 Analyzed by S. Squassoni (Carnegie Endowment for International Peace), “The realities of nuclear expansion,” USHR Select Committee on Energy Independence and Global Warming, 12 Mar 2008.

125 R. Black, “Nuclear needs ‘huge expansion,’” 16 Oct 2006, reporting Mr. Ritch’s remarks in Sydney, http://news.bbc.co.uk/2/hi/science/nature/6054986.stm.

126 Plant-by-plant nuclear data from IAEA and WNA; all data are at www.rmi.org/sitepages/pid256.php#E05-04. In 2010, the projected global net capacity increases are 79 GW for micropower (excluding standby and peaking cogeneration units), vs. 6 GW for nuclear.

127 See ref. 4, graphs 2, 3, and 5. An earlier version is M. Schneider and A. Froggatt, “On the Way Out,” Nucl. Eng. Intl., June 2005, pp. 36–38, www.neimagazine.com/story.asp?storyCode=2030047.

128 R. Smith, “Nuclear-Plant Analyses Ordered,” Wall St. J., p. A4, 18 Apr 2008.

129 Ref. 126. The World Nuclear Association data are from www.world-nuclear.org/info/reactors.html (Jan. 2008, date unspecified) vs. www.world-nuclear.org/info/reactors-jan07.html (Jan. 2007, date unspecified).

130 Windpower provided 12% of new U.S. capacity in 2005, 19% in 2006, and 30% in 2007.

131 Global Wind Energy Council, “Continuing boom in wind energy—20 GW of new capacity in 2007,” www.gwec.net/index.php?id=30&no_cache=1&tx_ttnews%5Btt_news%5D=121&tx_ttnews%5BbackPid%5D=4& cHash=f9b4af1cd0, 18 Jan 2008.

132 J. Dorn, “Global Wind Power Capacity Reaches 100,000 Megawatts,” 4 Mar 2008, www.earthpolicy.org/Indicators/Wind/2008.htm.

133 U.S. plants have lately averaged ~90% capacity factor (E. Blake, “U.S. capacity factors: A small gain to an already large number,” Nucl. News, pp. 27–32, May 2007, www.ans.org/pubs/magazines/nn/docs/2007-5-3.pdf), and the Nuclear Energy Institute’s preliminary Apr 2008 data suggest a record 91.8% in 2007 (www.redorbit.com/news/business/1339027/record_performance_by_us_nuclear_power_industry/).

134 European Wind Energy Association, “Wind energy leads EU power installations in 2007, but national growth is

inconsistent,” www.ewea.org, 4 Feb 2008.

135 Last assessed by the European Environment Agency in 2004, when fossil fuels and nuclear power got threefourths of all EU energy subsidies: http://reports.eea.europa.eu/technical_report_2004_1.

136 Lapse of the credit, which Congress typically holds hostage to subsidies for nuclear and fossil-fuel-burning facilities, reduced U.S. windpower installations by 93% in 2000, 73% in 2002, and 77% in 2004—an immense disruption to orderly industrial development (www.awea.org/newsroom/releases/AWEA_Market_Release_Q4_011708.html). These dramatic drops in orders, however, do not mean windpower is uneconomic without the credit—only that investors rationally preferred projects with the credit to projects without it, given a realistic process that lapsed credits would be reinstated. That is, uncertainties about future availability of the PTC undercut planning, investment, and hence development, not just of windpower but also of its manufacturing capacity and of transmission projects vital to exploiting the biggest wind resources. The PTC is well summarized by R. Wiser, “Wind Power and the Production Tax Credit: An Overview of Research Results,” LBNL/PUB-971, Lawrence Berkeley National Laboratory, 2007, http://eetd.lbl.gov/ea/ems/re-pubs.html. LBNL research suggests that longer-term renewal of the PTC may cut U.S. windpower costs by 5–15+%, whereas current short-term renewals add a capital risk premium of up to 12%.

 

to be continued…

 

NEWS BRIEF

OIL & GAS

ONGC to invest additional $600 mn in Imperial Energy

January 12, 2009. Oil and Natural Gas Corp (ONGC) is set to invest over $600 million for the development of assets of Imperial Energy, in addition to its acquisition price of $2.1 billion. ONGC acquired Imperial Energy after more than 97 percent of its shareholders had approved the deal last December. ONGC will invest $600 million to develop Imperial's strategic assets in the western Siberian region of Russia, which is one of the highest oil-producing regions in the world. ONGC wants to make Imperial's asset a platform for further expansion in the region. 

Chinese Cos may outbid OVL for 30 pc stake in Angola block

January 12, 2009. Chinese state-run oil majors CNOOC and Sinopec are learnt to have emerged frontrunners for the acquisition of 30% stake in an oil block in Angola from the US-based Marathon Oil. ONGC Videsh (OVL), the overseas arm of Oil & Natural Gas Corp, is also a contender for the stake. The successful bidder will have to pay about $1.8 billion for the stake. The move comes days after OVL announced acquisition of UK-based Imperial Energy for $2.1 billion, outbidding the Chinese firms. It has bid for Angola block number 32 to acquire 30% equity from Marathon Oil. It is yet to know the formal results of the bid. As per the industry sources, there is strong possibility of a Chinese company sealing the deal. ONGC has many times in the past lost out to the aggressive Chinese firms when it comes to acquisition of equity in overseas oil blocks. ONGC’s acquisition of Imperial was an exception, they added. Recently, Sinopec acquired Canadian firm Tanganyika Oil for $1.8 billion, outbidding OVL.

Tanganyika has two oil fields in Syria with proven reserves of 184 million barrels till end-2007. The sources also said that the valuation of the Angolan block was not justified in the wake of a massive fall in crude oil prices in recent times. Oil prices have declined to $40 a barrel from the peak of $147 in July 2008. On Angola’s block 32, Marathon Oil has announced 11 successful exploration wells. These are Gindungo, Canela, Gengibre, Mostarda, Salsa, Manjericao, Caril, Louro, Cominhos, Colorau and Alho. Marathon has a 30% working interest in this block. Total of France, which holds a 30% stake, is the operator of the block. The remaining stake is held by Sonangol (20%), Esso Exploration and Production Angola (15%) and Petrogal (5%). 

‘Gas production from KG fields expected by Feb-end’: RIL

January 12, 2009. Reliance Industries Ltd (RIL) has communicated to the Petroleum Ministry about the status of gas production from the D6 block in the KG basin. The company is said to have informed the Ministry that based on the current progress of installation work, it expects to be in a position to start trial production of gas from the fields by late February. RIL is also ready with the east-west pipeline network to ferry the D6 gas. Currently, the company is sourcing gas from other suppliers to test its network. The Government’s gas utilisation policy mandates the producer to sell gas to fertiliser and power sector on a priority basis. RIL has already sourced 5 million standard cubic metre (mscm) of gas from GAIL (India) Ltd for testing sections of its 1,386-km east-west pipeline and is sourcing another 20 mscm from them at the prevailing market price. The pipeline runs from Kakinada in Andhra Pradesh to Baruch in Gujarat. The actual requirement of gas for RIL to commission the pipeline network is far more (close to 100 mscm). Meanwhile, the company had to put off delivery of crude oil from the same fields to February 15 due to equipment failure. Reliance has already started crude production from the predominantly gas-rich D6 block in September last year. But on December 9, 2008, production was shut down following pipe ruptures at the floating, production, storage and off-loading vessel (FPSO). Reliance is the operator, with a 90 per cent stake in the D6 block. Niko Resources of Canada holds the remaining 10 per cent.

ExxonMobil sets sight on Sandakan basin

January 9, 2009. ExxonMobil is reportedly plans to invest around $100mn for exploring oil and gas in southwestern Philippine waters. The Philippines Department of Energy (DoE) documents, refers to a mid-2008 farmout under which Mitra Energy farmed out a 50% interest and operatorship of Service Contract 56 to ExxonMobil. The Philippines DOE approved the farmout in July 2008. The partnership plans to drill two deepwater exploration wells in 2009.

Fall in crude, refinery margins may dent oil Cos' bottomline

January 12, 2009. India’s petroleum majors are likely to post a fall in profits as well as revenues when they announce their results for the quarter-ended December 31, 2008, later in the month. The crash in crude oil and polymer prices, coupled with a decline in refining margins, is likely to result in heavy inventory losses. On the other hand, the current scenario could also serve as a springboard for some of them- particularly companies with oil marketing and gas transmission operations- to report a better performance in the year-ending quarter. Oil prices fell by over 55% during the December quarter, much steeper than the 30% fall in the September 2008 quarter. Thus, going by the September quarter’s performance of domestic petroleum firms- PSU oil refiners posted unprecedented losses- the December quarter could be worse. The weak rupee will also have a negative impact for refiners, but bring a relief for oil producers.

Essar Oil to sign MoUs at VGGIS

January 11, 2009. Essar Oil plans to sign four major MoUs with proposed investment of Rs 210 bn, with the state government, in the Vibrant Gujarat Global Investors' Summit 2009 scheduled to begin on Jan 12 ‘09. The MoUs to be inked includes expansion plans of their Vadinar refinery in Jamnagar and petrochemical complex to be set up at Vadinar where the refinery is located.

Indian Oil seeks Rs 100 bn for Paradip refinery

January 11, 2009. Indian Oil Corp. has reportedly borrowed Rs 100 bn ($2 billion) for its 15 MMT Paradip refinery project. The company plans to borrow a total Rs 147 bn for the refinery, which is scheduled to be completed by 2012. The refiner plans to complete the raising of funds by next month.

Cairn India to scale price of Rajasthan oil to Indonesian crude

January 12, 2009. According to Cairn India, it might benchmark the price of crude oil from its Rajasthan find in western India with Indonesian crude varieties as in terms of chemistry, the crude is closest to Indonesian crude. The Gurgaon-based explorer plans to start production from the Rajasthan oilfields in the second half of this year, with peak production pegged at 175,000 barrels a day.

GAIL reduces gas supply to Gujarat Gas by 2 pc

January 9, 2009. Consequent to the indefinite strike by the PSU oil companies workers association with effect from January 07, 2009, supply of natural gas from GAIL to Gujarat Gas has reduced to about 2% of the normal levels of 2.27 mmscmd under two separate contracts. Supplies from GAIL account for more than 80% of the Company's total gas supply. This has affected Gujarat Gas's sale of gas mainly to industrial customers. Gas supply from the Company's other suppliers continues at near to normal levels.

Reliance Industries ceases gasoline sale to Iran

January 8, 2009. A non-profit organization, Foundation for Defense of Democracies (FDD), said Reliance Industries has stopped gasoline sale to Iran, following a group of US Congressmen urging the country's Exim bank to suspend assistance to the Indian firm, until the Indian conglomerate stops business with Iran. The US Export-Import Bank, which provides support to the US exporters, approved $900 million in loan guarantees to expand the Jamnagar oil refinery used by the RIL to refine petroleum for sale to Iran. Members of Congress wrote letters to the Exim Bank demanding a full investigation into these loan guarantees. Meanwhile, RIL's agreement for supplying gasoline to Iran was till December and the Indian firm has not renewed the contract as financial institutions are not ready to provide Iran with the line of credit needed for the same, in light of the US sanctions. Further, the Executive Director of FDD, Mark Dubowitz said that the Iranian regime is responsible for abusing its own citizens and murdering innocent civilians throughout the world. He said that providing the gasoline that fuels the Iranian regime and its military is simply bad business. He mentioned that the other companies exporting gasoline to the regime should follow Reliance's lead. The foundation in its statement said although Iran is a major oil producer, it must import 40 per cent of the refined oil it needs because it lacks the refining capacity to meet its internal consumption. Reliance provides Tehran with about 25 per cent of its refined oil imports or around 10 per cent of the Iran's total gasoline consumption. The FDD, is the only non-partisan policy institute dedicated to promoting pluralism, defending democratic values and fighting the ideologies that threaten democracy. 

ONGC to invest $5.3 bn in gas finds by 2013

January 13, 2009. Oil and Natural Gas Corp (ONGC) will invest $5.3 billion in developing gas finds in two of its eastern offshore Krishna Godavari basin blocks to produce 25 million standard cubic meters per day of gas by 2013. The Directorate General of Hydrocarbons has approved its appraisal plan for the gas discoveries in deep-sea block KG-DWN-98/2. It plans to drill six appraisal wells to assess the potential and delineate the discoveries. The block sits next to Reliance Industries prolific KG-DWN-98/3 or D6 block. ONGC plans to tie up 10 discoveries in KG-DWN-98/2 with the G-29, GS-4 and Vashistha gas finds in a shallow water block KG-OS-DW4 in the same basin. Besides natural gas, ONGC also plans to produce 8,000 barrels of oil per day from the fields. The reserve estimates and production plan in ONGC's appraisal programme, however, excludes ultra-deepwater UD-1 discovery in KG-DWN-98/2 block. The UD-1 discovery alone has been certified by DGH to hold just over 2 Trillion cubic feet of inplace gas reserves. Ten discoveries in KG-DWN-98/2 (excluding UD-1) and three in adjacent block together hold 6.37 Tcf of inplace reserves. Without UD-1, the block is assessed to hold just over 5 Tcf of inplace gas reserves. ONGC has roped in Statoil of Norway and Petrobras of Brazil as equity partners in the KG-DWN-98/2. Statoil and Cairn India hold 10 per cent each in the block and Petrobras 15 per cent, while ONGC has the remaining.

RIL asks Govt to free retail fuel prices from admin control

January 13, 2009. Reliance Industries on Tuesday asked the government to free retail fuel prices from administrative control and said only fiscal measures should be used to moderate prices for consumers. RIL's President for refinery P Ragavendran said the government should intervene to regulate process through fiscal measures and not resort to capping the rates at any time. He said that the private sector can now reopen petrol pumps (after international fuel prices fell to four-year lows). Reliance had last year shut all its 1,450 petrol pumps in the country after it was unable to compete with public sector companies, who could sell fuel at rates lower than the production cost on getting compensated by the government.

Excise-blended retail fuel may be back

January 13, 2009. The government may again impose an excise duty of Re 1 per litre on non-branded petrol and diesel. The tax proposal put forward by the finance ministry comes at a time when the petroleum ministry is planning to cut retail prices by as much as Rs 5 a litre for petrol and Rs 3 a litre for diesel. In other words, if the excise duty is reimposed, the effective price cut for consumers could be Rs 4 a litre for petrol and Rs 2 a litre for diesel.

Oil companies are making a profit of Rs 11 a litre on petrol and Rs 4 a litre on diesel due to reduction in prices of imported crude oil. Crude oil, that was at $129 a barrel in June 2008, is now at $39 a barrel. At that time, the government had been compelled to use a mix of retail price hikes and indirect tax cuts to keep fuel affordable for consumers. The finance ministry too had reduced excise duty on unbranded auto fuels by Re 1 a litre to provide relief from surging global oil prices. It had led to a loss of Rs 22,660 crore to the exchequer. Now that crude oil prices have dropped, the government is not willing to pass on the entire savings to consumers. This is mainly because public sector oil companies, such as Indian Oil Corp (IOC), Bharat Petroleum Corp and Hindustan Petroleum Corp, are still losing money on cooking gas and kerosene sold in ration shops, the minister said.

IOC is still losing Rs 12.16 a litre on kerosene and Rs 32.97 on every domestic cooking gas cylinder. In November 2008, excise duty collections declined 15% and Customs duty collections by 0.8%. These are expected to plummet 40% in December after an excise duty cut of 4% on a wide group of products to stimulate the economy. The government may end up losing more than Rs 40,000 crore due to various post-Budget duty cuts. Additional expenditure in the current financial year could take the country’s fiscal deficit to as high as 5% of GDP, against a target of 2.5%. 

India may sign oil and gas sector MoU with Canada

January 12, 2009. India may sign memorandum of understanding (MoUs) with Canada for cooperation in oil and gas sectors. The MoU may also enable Indian exploration firms to explore oil sands in the country. New Delhi may also sign similar agreements with Syria and Mozambique.

Bombay HC asks government to clarify gas price

January 12, 2009. In an interesting development to the Reliance Industries-Reliance Natural Resources Ltd case, the division bench of the Bombay High Court has asked government counsel Mohan Parasaran to clarify the price at which gas from the Krishna-Godavari basin block would be sold to government. This was in respect to the long pending dispute between Reliance Industries and Reliance Natural Resources over the supply of gas, where the government is acting as an intervener. Justice J N Patel of the division bench sought to know from the government, the price at which the state-owned National Thermal Power Corporation will be buying gas from RIL, as the RIL-RNRL gas sales purchase agreement is based upon the RIL-NTPC gas sales purchase agreement.

The government will file its reply as the price may have a direct bearing on NTPC, which is also engaged in another legal battle with RIL on supply of gas. NTPC is fighting a case in the Bombay High Court against RIL, seeking the RIL to honour its gas sales agreement, which is not related to pricing. RIL through an international competitive bid agreed to supply 12 million metric standard cubic meters per day (mmscmd) of gas to NTPC, at $2.34 per mmbtu for 17 years. The government through an empowered group of ministers (EGOM) has approved a benchmark price of $4.2 per mmbtu for sale of gas from RIL's KG basin fields. However, this decision was without any pre-judice to the RIL-RNRL and RIL-NTPC case.

‘Windfall tax not applicable to private players’: PetroMin

January 12, 2009. The ministry of petroleum and natural gas clarified that there was never any proposal to apply windfall tax to private oil producers in the country. Special secretary of the ministry Rita Menon said that the windfall tax had been a proposal to "formalise" the discounts offered by state-run oil producers as part of the subsidy-sharing mechanism. It had been also mentioned in the B.K. Chaturvedi committee report on the oil sector, which was yet to be accepted by the government. As per the proposal, the government would consider taxing a part of the earning if the oil price went above $75 per barrel. The proposal had gained ground when the oil producers, ONGC and Oil India Ltd. earned profits due to the high prices that reached a peak of $147 last June, which have since gone down drastically to below $39. Special secretary also said that it was only applicable to blocks which had been allotted on negotiation or nomination basis.

ONGC may get upto 40 pc in Kazakh block

January 12, 2009. ONGC Videsh is close to getting an stake in the Satpayev exploration block in Kazakhstan. It hopes to get 30-40 per cent stake in the block. Oil secretary RS Pandey and ONGC Videsh officials have gone to Kazakhistan to finalise the deal. ONGC Videsh is the overseas arm of state-run explorer Oil and Natural Gas Corp. 

ONCG to tie-up with Schlumberger for shale gas

January 12, 2009. Oil & Natural Gas Corp. is set to tie up with multi-national oilfield services provider Schlumberger for exploring shale gas potential in the country. As per the Planning Commission there is no data available about shale gas reserves in the country. The Government has been encouraging oil companies to explore hydrocarbons by providing enough tax benefits. There are provisions in the Income Tax Act 1961.

‘Govt for competitive, market oriented hydrocarbon sector’: Pranab

January 12, 2009. According to the External Affairs Minister, Mr Pranab Mukherjee, the Government favours a competitive and market oriented hydrocarbon sector with increasing private sector and foreign investment in all the important segments of the industry. The main challenge is to ensure the “continuous availability of safe, clean and accessible energy at commercially competitive prices”. The Minister added that energy security concerns were central to the country’s national interest and an important aspect of the economic diplomacy. Terming the recent terror attacks in Mumbai as a “direct strike” at the country’s economic development, the External Affairs Minister said that the attack underscored the risk all countries face from economic sabotage. He said that the global hydrocarbons sector would increasingly be even more vulnerable to such threats. He is of the view that protecting these assets would not simply be a law and order problem for an individual country, whether an energy exporter or consumer. He stressed that stability of energy supplies, security of energy transportation and creation of new energy infrastructure and its protection have to be a common goal requiring coordination and cooperation of all countries. The Petroleum Minister, Mr Murli Deora, said, “We can work towards energy dependence only through interdependence – cooperation between producers and consumers to assure a bright energy future for the betterment of mankind.” Experience has taught that very low prices and very high prices are not sustainable, the Minister said, adding that during periods of low oil prices, capital tends to move out of energy to sectors offering higher returns. The result is under investment in new capacity across the spectrum of industry – including production, transportation, refining, distribution and marketing. The Minister said, at the same time, ‘low-priced’ energy consumption encourages greater consumption. The minister explained that the challenges ahead of us are not the challenges of resources (coal, nuclear, solar, wind power, natural gas, and other alternatives) or what I call ‘availability’ but it is the challenge of ‘deliverability’. Elaborating he said, deliverability is a measure of the industry’s ability to boost the production capacity, transportation and refining, and delivery of energy to end consumers for their daily lives.

RIL-RNRL dispute to end soon

January 9, 2009. The Government has reportedly interfered to ensure that gas from RIL’s KG basin would be given to the proposed Dadri power project by Reliance Power. Thereby expecting the feud between RIL and RNRL may soon come to an end. External Affairs Minister Pranab Mukherjee, who heads the Group of Ministers (GoM) dealing with the natural gas issue, has concluded that RIL would provide gas to Reliance Power for its 7,480 MW gas-based power project in Uttar Pradesh, subject to the availability of fuel.

POWER

NTPC to set up 460 MW hydel project in Mizoram

January 12, 2009. The NTPC has signed an agreement with the Mizoram government for execution of 460 mega watt Kolodyne Stage II Hydro Electric Project on the Kolodyne river in Sahia and Lawngtlai districts of Mizoram. At least Rs. 3,000 crore would be invested for this power project targeted to be commissioned within six to seven years. It will be the NTPC’s first hydro power project in the northeast and the second in the country after the 800 mega watt Koldam hydel power project in Himachal Pradesh. The NTPC is currently building the 750 mega watt Salakati thermal power project in lower Assam. The NTPC shall execute the project on Build, Own, Operate and Maintain basis. Project construction activities will start within six months. In accordance with the agreement, NTPC shall supply 13 per cent free power from the project to Mizoram. The corporation has also agreed to supply 15 per cent power at the tariff, to be determined by the Central Electricity Regulatory Commission, over and above the normal share of Mizoram as per the existing power-sharing formula, subject to the concurrence of the Power Ministry. Energy corresponding to 100 units of electricity is to be provided free of cost to the families affected by the project, notified by the Mizoram government in the designated resettled areas and project area for ten years from the date of commissioning. The cost of balanced unused electricity, if any, will made available to the families in cash or kind or both. The agreement states that hundred per cent recruitment for workmen will be done first from among the affected families and in case of non-availability of suitable candidates among them, the recruitment will be done from other residents of Mizoram.

NTPC and Power Company of Karnataka Ltd sign MoU

January 12, 2009. Central sector power PSU NTPC and Power Company of Karnataka LTD (PCKL) signed a MoU for development of 4000 MW Mega Power  Project at Kudgi in Bijapur district in Bangalore. As per the MoU, NTPC will setup its maiden 4000 MW Kudgi Super Thermal Power Project (Stage I - 3x500 MW + Stage -II 2x 800 MW). NTPC and KPCL also signed a MoU to setup 500 MW capacity Wind Power Projects in Karnataka.

BHEL, Karnataka Power sign pact for projects

January 12, 2009. Public sector BHEL and the State Government-owned Karnataka Power Corporation Ltd signed a joint venture agreement for setting up projects totalling 2,400 MW at Yeramarus and Yedlapur, both in Raichur district. The projects, costing about Rs 12,000 crore, would be implemented through a special purpose company. Infrastructure Development Finance Company would have a 48 per cent equity stake in the special purpose company. The remaining 52 per cent would be held by BHEL and KPCL equally. The project equipment comprising the boiler turbine generating (BTG) unit would be supplied by BHEL. This is BHEL’s second joint venture power project: The other being the 1,600-MW project at Udangudi, Tamil Nadu. The projects would be based on BHEL’s supercritical technology. BHEL had set up manufacturing capacities for supercritical generation sets ranging from 270 to 800 MW.

KPCL is also placing orders for BTG with BHEL for its Raichur unit eight of 250 MW and for its 500-MW BTPS unit three. In fact, all of KPCL’s thermal generation is powered by BHEL generation sets. The additions are likely to push up the gross capacity to about 13,000 MW by the end of the 12th Plan. While the BTG sets would be sourced from BHEL, the pricing would be benchmarked to international levels. This was despite the fact that BHEL’s BTG supply is not through engineering procurement and construction. International benchmarking also implied that BHEL would have to meet the stringent performance guarantee specifications offered by global manufacturers. BHEL already offers performance guarantees of about 85 per cent plant load factor.

Adani Power renegotiates equipment cost for Tiroda project

January 12, 2009. In an effort to take advantage of the meltdown in commodity prices, Adani Power Ltd (APL) seems to have renegotiated the cost of critical equipment with the Chinese contractor for its super critical coal-based 1,980-MW (3X660 MW) power project at Tiroda in Gondia district in Maharashtra.

The project is being executed by Adani Power Maharashtra, a wholly owned subsidiary of APL. The company recently renegotiated the Boiler, Turbine and Generator (‘BTG’) package with Sichuan Machinery and Equipment Import and Export Co Ltd. The renegotiated contract may reduce the project cost by up to 10 per cent, which is expected to a reduction of over Rs 800 crore. Adani Power, a subsidiary of Adani Enterprises, had filed a draft red herring prospectus to raise over Rs 5,600 crore through an IPO. According to the prospectus, the company was allocated two coal blocks at Lohara West and Lohara Extension for Tiroda. The project is expected to be fully commissioned by April 2012. Overall, APL proposed to set up six coal-based thermal power projects in Gujarat, Maharashtra and Rajasthan totalling 9,900 MW at an estimated investment of Rs 43,139 crore by 2011-2012. Of the six projects, the 4,620-MW coal-based Mundra power project is in advanced stage of implementation. Phase-I (660 MW) of the project, including two units of 330 MW, may come on stream in February. Work is also nearing completion for Phase-II (660 MW). Construction of phase III (2X660 MW) and IV (3X 660 MW) is underway. The entire project is expected to be commissioned latest by 2011. Mundra power project is located in the Mundra Port and SEZ area, also promoted by Adani Group. The critical equipment for the project is also sourced from Chinese contractors.

Second stage of Varahi hydro project launched

January 11, 2009. Karnataka's power woes eased a little with the inauguration of the second stage of the Varahi hydro electric project. The 230 MW project, costing Rs 291 crore, will deliver the much-needed peak hour power, saving the State a considerable amount of money.

The power generation from the station would save the State Rs 1.25 crore a day. The State was still facing a 1,700 MW shortage daily, and that the government was making multiple efforts in purchasing power through various agencies to make up for the shortfall. Power which was being purchased at Rs 7.25 paise per unit from sugar mill owners will now be sold to the State for Rs 6.50 paise.

Jindal group to set up 2 GW power plant

January 11, 2009. Jindal group announced setting up of 2,000 MW power plant near Simar port, along the coastline of Gujarat with an proposed investment of Rs 10,000 crore. Land has been identified, and the group has applied for various approvals for the power plant in Gujarat, and once that happens the work will commence. Once the work begins the power plant is expected to get commissioned within three years.

AP to set up nuclear power plant

January 7, 2009. Giving a boost to power generation, the Andhra Pradesh government will soon set up a nuclear power plant in the state to produce 2,000 MW of power. Nuclear Power Corporation of India and the state government-owned AP Genco will soon enter into a partnership agreement to set up the plant. Under the agreement, NPCIL will have 51 per cent stake in the JV, while the remaining will be with AP Genco. The state government has identified Cuddapah and Srikakulam for setting up the plant and both the sites would be studied before taking a final decision. Andhra Pradesh possessed second highest uranium reserves after Jharkhand. With the expected commissioning of various power projects, the state would see net addition of 13,000 MW capacity in the near future which is a record compared to other states.

Power supply assured to industries

January 13, 2009. Chamundeswari Electricity Supply Company (CESC) has assured Mysore industrialists and urban users of uninterrupted power supply. The company promised to permit surrendering of power within 25 days from the date of application instead of 60 days and help industries, which are surrendering the allotted power due to changed circumstance. The company agreed to a suggestion for constituting a vigilance unit to monitor the theft of transformer oil in co-operation with the Karnataka Industrial Area Development Board and the Mysore Industries Association (MIA).

Powergrid commissioned Ranchi-Sipat line

January 12, 2009. In line with the plan to establish an Integrated National Grid in a phased manner Powergrid, on Dec 31, 2008, commissioned Ranchi-Sipat 400 kV Double Circuit transmission line thereby enhancing power transfer capacity between Eastern and Western Regions by 1200 MW to make it 3000 MW. Earlier that month, the company enhanced the power transfer capacity between Eastern and Northern Regions by 500 MW to make it about 4000 MW by utilizing inherent capability of Biharshariff – Sasaram - Allahabad link. With these achievements, total inter-regional power transfer capacity of National Grid has been enhanced to 18,700 MW from existing level of 17,000 MW. Till date no constraints in evacuation of power from Central Sector generating stations has been faced on account of POWERGRID's transmission network. In fact establishment of National Grid by POWERGRID is also facilitating transfer of short term surplus power from any where to any where in the country from generation under State and Private sector as well.

The company also plans to enhance the capacity of National Grid to more than 37,000 MW by end of XI Plan through strengthening of regional grids and building more inter-regional links, for which an investment of Rs 55,000 crore is planned during the plan. With regard to mobilization of requisite debt funds POWERGRID is placed in a comfortable position. Currently loans to the tune of $ 2.2 Billion (Rs. 10,000 Crore) from The World Bank and Asian Development Bank has already been tied up or in the advanced stage of finalisation. For balance funding also discussions are on with funding agencies at national and international level. POWERGRID- a Navratna PSE has emerged as one of the largest transmission utilities in the world operating around 69,500 ckt. kms. of transmission lines and 116 Substations with a transformation capacity of 77,200 MVA. 

MCX launches futures trading in electricity

January 9, 2009. Multi Commodity Exchange (MCX) has launched futures trading in electricity for the first time in India. Globally, Nordpool in Sweden, Norway, Finland and Denmark, Inter Continental Exchange in UK, Powernext SA in France, European Energy Exchange in Germany, PLM in the US and Australian Securities Exchange in Australia offer electricity futures trading platform. MCX received the approval from market regulator Forward Markets Commission for launching weekly and monthly electricity contracts. The exchange will launch eight weekly contracts and four monthly contracts. The first trade was executed in the March monthly contract at Rs 7,300 a MWh. On day one, trading in electricity futures was lacklustre. In the first session, which ended at 5 p.m., there were only two trades valued at Rs 3.5 lakh on a volume of 48 MWh. The open interest was zero. The exchange recorded a turnover of Rs 6,828 crore in the first half of the trading session up to 5 p.m. The contract trading unit will be 1MWx24 hours with tick size as Rs 1 per MWh. The delivery will be optional for both buyers and sellers and due date rate will be the average of daily system prices of day-ahead market of Indian Energy Exchange (IEX) for delivery during the contract week/month. It will be traded from Monday to Saturday between 10 a.m. and 11.55 p.m., except Saturdays which will be from 10 a.m. to 2 p.m. The annual market size (electricity generation) in 2007-08 was Rs 2 lakh crore (for 665 million MWh @ Rs 3,000 / MWh) i.e. about 665 billion units. The present short term market per year is about 4 to 5 per cent of the total market which works out to Rs 13,500 crore (30 million MWh @ Rs 4,500 per MWh) which is equivalent to about 30 billion units. With the launch of electricity futures, MCX has further diversified its basket of energy products after crude oil, furnace oil, natural gas and aviation turbine fuel. Now the industry will be able to mange price risk on energy-related raw material or output better on MCX, which already accounts for 98 per cent of the entire energy-related futures market. The large number of participants, including inter-state generating stations, distribution licensees, state generating stations, captive power plants and independent power producers, electricity traders and others, are exposed to price risk due to uncertain demand and supply and volatile prices. The launch of electricity futures will smoothen the price curve in the medium to long run that will help the market participants to facilitate price discovery and take an informed decision looking at the futures prices.

Power projects will get to share captive coal

January 13, 2009. The government has relaxed captive coal mining norms to allow power companies to divert surplus coal from one of their projects to another. Permission will be given on a case-to-case basis to coal-surplus companies that approach the coal ministry. The company’s claim will be verified by the coal ministry before the diversion plan is approved. Permission will be given to only those power projects that are awarded on the basis of tariff-based bidding. However, the regulations bar power companies from selling surplus coal to other companies as only government-owned entities are allowed to trade in coal. Allowing private sector companies in trading will need an amendment to the Coal Mines (Nationalisation) Act, 1973. The current norms require captive coal mines to hand over excess coal to the central government, which disburses it through Coal India, a company owned by it. In some special cases, the coal ministry permits sale of excess coal on a temporary basis. A recent decision by a group of ministers allowing Reliance Power to divert surplus coal from its Sasan captive mines to another power project at Chitrangi in Madhya Pradesh had run into controversy as the permission was given even before mining started at the site. Tata Power had challenged the decision in the Delhi High Court. Till now, 198 captive coal blocks have been allocated by the coal ministry. Only 21 of these blocks are operational so far. Captive mining was allowed to give a fillip to coal production in the country as the government expects a demand-supply mismatch. Planning Commission has estimated a shortfall of 60 million tonne by 2012. 

‘Civil nuclear programme offers scope for big investments’: Singhvi

January 12, 2009. According to Dr. Abhishek Singhvi, MP and Chairman, India-US Forum of Parliamentarians, India’s civil nuclear energy programme offered a $160 billion investment opportunity over the next 20 years as the country embarks on ramping up atomic power capacity to an estimated 63,000 MW by the year 2032. He said that it was imperative to amend the Atomic Energy Act of 1962 to facilitate private sector participation in nuclear power generation as it was not possible for the Government alone to cough up the massive requirement of funds for the country’s nuclear power programme.

CLP India to buy distressed projects in the power sector

January 11, 2009. The India arm of Hong Kong-based CLP Group plans to take over projects in the country that may be surrendered by developers, who find it tough to raise resources in a tightening credit market. CLP, founded in 1901 as China Light and Power Co. Ltd in Hong Kong, is among the two significant overseas entrants in India’s power generation sector along with US-based AES Corp. CLP has recently been awarded the contract to build a 1,320 MW coal-fuelled project at Jhajjar in Haryana. CLP has also been approached by bankers to take minority equity stakes in power projects that are facing financial constraints. In 2003 CLP acquired Gujarat Paguthan Energy Corp. Pvt. Ltd, which has a 655 MW gas-fired combined-cycle power station, making the company one of the largest foreign investors in the domestic power sector. The company’s plans for an additional 1,000 MW of gas-based generation expansion has, however, been stuck for want of gas. The company is also scouting for opportunities in the hydropower sector. While India has a power generation capacity of 145,006 MW, the 11th Plan (2007-12) has set a target of additional 78,577 MW capacity, requiring at current estimates, some Rs10.31 trillion in investments. But according to the power ministry, the government expects to face a Rs 4.51 trillion funding shortfall. The problem has worsened due to the financial crisis with a lot of private sector projects still awaiting financial closure.

Free electricity to families affected by Himachal hydropower projects

January 10, 2009. Free electricity would be given to families affected by hydropower projects of Himachal Pradesh Power Corporation Ltd (HPPCL) in the state. The HPPCL, a public sector undertaking, has seven mega hydropower projects, including the Rs 27 billion (Rs.2,700 crore or $561 million) Renuka Dam that will provide drinking water to Delhi. The government will now provide 100 units of power free for 10 years to each of the project affected families, besides a series of other economic benefits. So far, only Sai Engineering Foundation, an NGO that has set up a mini hydro project in Kullu district, had taken the initiative to provide free power to a village located near the project. The government has also decided to provide free medical facilities to the affected families. The Delhi Jal Board, which will get 23 cubic metres of water per second once the project is completed, has given Rs 2 billion (Rs 200 crore) to Himachal Pradesh. As per an agreement signed in 1994, while Delhi will get water from the Renuka dam till the Kishau and Lakhawar Vyasi dams in neighbouring Uttarakhand become operational, Himachal Pradesh will have the rights to the 40 MW power generated through the project.

Kerala opposes move to take NTPC plant into Central pool

January 9, 2009. Kerala has opposed the move to take the Kayamkulam plant of National Thermal Power Corporation (NTPC) into the Central pool, which will force it to share the power from there with other States. The 360 MW plant was set up in 1995 exclusively for meeting the power requirements of Kerala. From 2003 onwards, power from there was being shared with Tamil Nadu, with Kerala drawing 180 MW. Kerala has so far paid Rs 1,474 crore to NTPC as fixed charge for power from the plant, which was set up at a cost of Rs 1,200 crore. In the beginning, the power was priced at Rs 2.50 per unit, which subsequently went up to Rs 13 per unit following huge increase in the price of naphtha. The State had been paying the fixed charge even when it was not using power from the plant in the wake of the unprecedented rise in the cost per unit. Now, when the price of naphtha has come down, States such as Andhra Pradesh and Karnataka have put up demand with the Centre for sharing the power from the plant. The power crisis in Kerala state was continuing unabated and there was urgent need to bring down consumption through energy conservation measures. As part of it, the Kerala State Electricity Board (KSEB) has decided to distribute 10 lakh CF lamps, which will commence from the middle of February. The lamps will be distributed free of charge to consumers under Scheduled Castes and Scheduled Tribes and to below-poverty-line (BPL) consumers belonging to those local self-government bodies that have initiated the measures prescribed by the Total Energy Security Mission. The lamps thus distributed will have one-year replacement guarantee. Along with this, an incentive scheme will be implemented for domestic consumers, under which those who reduce the power consumption will be given a CF lamp free of cost. To be eligible for the scheme, the monthly consumption should be reduced by 10 per cent and a minimum of four units.

Coal imports growing at 17 pc annually

January 8, 2009. Coal imports have recorded a compounded annual growth rate (CAGR) of 17.1 per cent between 2003 and 2008. Simultaneously, exports of coal have come down during this period with a CAGR of (-) 0.1 per cent, according to a report published by the credit rating agency ICRA Ltd.

Import trend
(in %)
Year	Coking coal	Non-coking (Thermal)	Coke	Total
2003	12.95	10.31	2.25	25.51
2004	12.99	8.69	1.89	23.58
2005	16.93	12.03	2.84	31.79
2006	16.89	21.70	2.62	41.21
2007	17.88	25.20	3.80	46.88
2008	21.50	28.50	6.26	56.26
5-year CAGR	10.7	22.5	22.8	17.1

Import is growing an all types of coal - coking coal, non-coking coal as well as coke - mainly because of the low calorific value of domestic coal and shortage in domestic production. According to the report, despite shortage in domestic supply and the growing trend in imports, large-scale imports of thermal coal by the power sector are ruled out because the boilers of many existing power plants are not designed to handle coal with high calorific value, inadequate handling facility in the Indian ports, volatility in international coal prices, high ocean freight rate, foreign exchange risk and inadequate inland transport infrastructure. However, coking coal used by the steel sector is expected to further go up, particularly in view of the new steel capacities that are coming up. The ICRA study has pointed out that the coking coal supplied by Coal India Ltd to the steel plants of Steel Authority of India Ltd from the coking coal reserves at Jharia and West Bokaro Coalfields have deteriorated steadily and now has an ash content of around 18-20 per cent as against an ash content of 9-10 per cent in imported coal. The report further pointed out that the steel manufacturers import around 50 per cent of their coal requirement and 95 per cent of India’s imports are from Australia.

India to sign global pact on nuclear liabilities soon

January 8, 2009. India has initiated the process of signing an international convention on nuclear liability issues and the matter would be taken up by the Cabinet for a decision shortly. International nuclear firms, led by US companies, have been lobbying hard for India to adopt the International Atomic Energy Agency’s (IAEA) Convention of Supplementary Compensation for Nuclear Damage (CSC). The convention, among its provisions, places the onus of compensation in case of nuclear damage on the ‘Installation State’ (where the nuclear facilities are located), in this case India. The CSC, seen as a step forward in the international nuclear liability regime embodied in the Vienna Convention on Civil Liability for Nuclear Damage of 1963 and the Paris Convention on Third Party Liability in the Field of Nuclear Energy of 1960, mandates the ‘Installation State’ to give 300 million SDRs (Special Drawing Rights, the unit of account defined by the International Monetary Fund) or a higher amount as compensation. It also holds the operator of a nuclear installation liable for damage if adequately proven. The Government hopes to scale up nuclear power capacity to 60,000 MW by the year 2030.

Coastal power projects may have to import 30 pc of their coal needs

January 7, 2009. Coastal power projects under construction may have to mandatorily import 30% of their coal requirements if the developments at a standing linkage committee meeting hold sway. Non-coastal projects, meanwhile, may be required to source 10% of their requirements from either overseas or sources other than Coal India. At a meeting, which was held recently, it was suggested that any power project coming up within 150 km of a port may be termed as a ‘coastal power plant’ for the purpose of earmarking a definite import content in their fuel mix. According to a shipping ministry the port sector is capable of handling 60 million tonne (MT) of coal a year at major ports and this quantity can be enhanced by 2 MT a year in the next few years. Interestingly, the power sector has been at loggerheads with Coal India (CIL) over the fixing of the trigger point for the fuel supply agreement (FSA). While the sector has been asking for a 90% trigger point, CIL has been asking for 60%. The coal ministry, on the other hand, wants a trigger point of 75%. FSAs involve a commitment for supplying a certain volume of coal as agreed upon by Coal India (CIL) and the consumer. A 75% trigger point would mean that CIL would have to pay penalties if it fails to supply that percentage of the agreed volume. On the flip side, if the consumer would be liable to pay a fine if it does not lift at least 75% of the agreed volume. The rise in demand for coal has long outpaced CIL's production growth, thereby resulting into a need to import coal. This year, the power sector is expected to import about 20 MT of coal for existing power plants. This figure is set to inflate as more projects begin generating power.

KSEB plans capital investment of Rs 13.7 bn in ’09-10

January 7, 2009. The Kerala State Electricity Board (KSEB) has projected a total capital investment of around Rs 1,370 crore, covering generation, transmission and distribution sectors, in 2009-10. In its application to the State Electricity Regulatory Commission for approval of Aggregate Revenue Requirement (ARR) and Expected Revenue from Charges (ERC) estimates for the year, the board has put the capital outlay for the generation sector at Rs 403.33 crore. The outlay is for five ongoing projects, 16 new schemes and seven wind and non-conventional energy projects. Besides, provisions have also been made for additional capitalisation of 11 completed hydro-electric projects and two thermal projects and renovation and modernisation works of five existing hydro-electric stations. The ongoing hydel projects for which capital investments have been planned include Kuttiyadi Extension (50 megawatts), Kuttiyadi Additional Extension (100 MW) and Pallivasal Extension (60 MW). The total outlay for the ongoing projects is Rs 74.26 crore. The tendered projects have been provided a total of Rs 64.60 crore and these include Thottiar (40 MW), Sengulam Augmentation (85 million units), Ramakkalmedu wind farm (5 MW) and Athirappilly (163 MW). The capital outlay for the generation sector also provides Rs 29.30 crore for renovation and modernisation, Rs 20 crore for the proposed Baitharani coal project in Orissa and Rs 26 crore for rebuilding of the Sabarigiri hydel project. The transmission sector is projected to require a total investment of Rs 366.73 crore. The works proposed to be taken up include installation of 220 KV sub-stations and connected lines (Rs 88.50 crore), 110 KV sub-stations and connected lines (Rs 150 crore), 66 KV sub-stations (Rs 60 crore) and 33 KV sub-stations (Rs 35 crore). The distribution sector has been earmarked a total of Rs 600 crore. These apart, the board plans to invest Rs 83 crore for facilitating IT-enabled services and Rs 3.90 crore for institutional development programmes.

OIL & GAS

Dana's new discoveries to double Egyptian gas reserves

January 13, 2009. Dana Gas, the Middle East's first and largest regional private sector natural gas company, has announced that its current drilling campaign in Egypt has led to yet another significant gas and condensate discovery at its Salma-1 well in its Nile Delta Concession. The news follows announcement by the company of a significant discovery of gas and condensate reserves, estimated in excess of 130 billion cubic feet (bcf) of gas, at its El Basant-2 well, also in the Nile Delta Concession. The Salma-1 well is the Company's second well drilled in the West Qantara Concession, approximately 15 kilometers from Dana Gas's South Manzala gas processing facilities. It was spudded on December 1, 2008, reaching a total depth of 2,231 meters. The first production test on the well was initiated before the end of December 2008. The well penetrated 25 meters of net pay in the good quality sandstone reservoir of the Abu Madi formation, and additional reserves are currently estimated to exceed 150 billion cubic feet of gas. An additional four meters of sandstone gas pay was encountered in the shallower Kafr El Sheikh formation. Dana Gas ended 2008 with a daily production rate from its Egyptian operations of 31,640 boe and an average annual rate of 28,900 boe. Dana Gas' aggressive drilling programme in the past year has yielded multiple discoveries in different areas of its Egypt concessions, significantly enhancing the Company's reserves. Consequently, both production rates and asset valuations are set to be enhanced in 2009.

Petrobras sets export record of 620,000 bpd for December

January 13, 2009. In December, Petrobras set an exports record of 620,000 barrels per day (bpd) of national oils, topping out at 19,234,000 barrels in the month. Most to the exports (63%) were shipped to the United States, while, 21.4% went to Europe, 5.4% to South America, 5% to Asia, and 5% to the Caribbean. This record surpassed the previous 574,000-barrel-per-day mark, set in October 2008, by 46,000 barrels.

StatoilHydro discovers oil at Dompap prospect in the Norwegian Sea

January 13, 2009. An oil discovery north of the Norne field in the Norwegian Sea will be considered for development with the Norne production and storage ship. A well on the North Sea Verona prospect is dry. Drilling of an exploration well on the Dompap prospect off the coast of Nordland county has been completed after proving oil. A sidetrack drilled to establish the oil/water contact in this discovery is also in the process of completion. The wells are the 22nd and 23rd in production license 128, awarded in 1986 as part of Norway's 10B licensing round. In addition to StatoilHydro as operator with 64.0%, licensees in production license 128 are Eni with 11.5% and Petoro with 24.5%.

Chevron raises gas production by 11 pc in Bangladesh

January 12, 2009. U.S. energy major Chevron has raised natural gas production in Bangaldesh by more than 11 percent to about 500 million cubic feet (mmcf) per day to meet shortages. Bangladesh faces shortages of upto 250 mmcf per day, leaving it unable to supply hundreds of newly-built manufacturing firms. As per the state-run Bangladesh Oil, Gas and Mineral Corporation or Petrobangla, it has asked the U.S. major to produce more gas from Bibiyana field to meet rising demand. Some experts have suggested that production from current proven reserves of 2.51 trillion cubic feet at the field should not exceed the present quantum of 450 mmcf per day. As per the contract with Chevron, the firm may extract 497 mmcf per day. As per the Chevron, the Bibiyana field had produced better than expected since its start-up in March 2007, indicating that field was likely to be bigger than originally thought. The firm said an assessment of reserves by a third party indicated reserves were much higher than the initial assessment, conducted in 2000 before the field was developed. Bangladesh, with 13.54 trillion cubic feet of proven and recoverable gas reserves, can now supply up to 1,800 mmcf of gas daily against a daily demand of 2,050 mmcf.

Cuba produced 4 mt of oil and gas in 2008

January 9, 2009. State-owned Cubapetroleo produced the equivalent of more than 4 million tons of oil and accompanying gas in 2008, up 1.3 percent over the previous year. Cupet said the deposits in that region accounted for more than 60 percent of national production. The state company's biggest priorities for 2009 include carrying out geological studies and drilling in new areas and partnering with foreign companies. Cuba annually produces 47 percent of the fuel it consumes, while its natural gas output generates 15 percent of the country's electricity. In 2007, the Cuban energy industry said it produced 2.9 million tons of crude and 1.1 billion cubic meters (38.8 billion cubic feet) of natural gas. The Caribbean country currently produces roughly 51,000 barrels of oil per day but it has the potential to pump 700,000 bpd by 2015. As per the Center for Cuban Business Studies at Ohio Northern University, to achieve such an exponential increase in production Cuba will need $20 billion in investment. The Center is of the view that the experience of Sudan and other non-democratic countries shows that foreign companies will invest in Cuba to develop its crude reserves despite human rights abuses and a lack of free and fair elections. But if the United States were to lift its 47-year-old economic embargo against the communist-ruled island, Cuba's transformation into an oil economy would be much faster. The island currently depends on subsidized crude imports from close ally Venezuela to make up for what it does not produce at home. Cubapetroleo recently raised its estimate for crude reserves in the North Cuba Basin to 20 billion barrels, but the U.S. Geological Survey has not budged from its own estimate indicating that Cuba holds 4.6 billion barrels in that region.

NZ's Tui oil production hits 20 million barrels

January 9, 2009. The Tui area oil field in New Zealand's offshore Taranaki basin reached another significant milestone with the production of the 20 millionth barrel of Tui oil. The achievement comes less than eighteen months after production began on July 30, 2007. The Tui area oil field includes three producing reservoirs, Tui, Amokura and Pateke and lies 50 km off the Taranaki coast. The Tui area oil field is operated by a joint venture comprising Pan Pacific Petroleum NL (10%), Australian Worldwide Exploration Limited (42.5% and Field Operator), Mitsui Ltd (35%), and New Zealand Oil & Gas Limited (12.5%). When the investment decision was taken by the joint venture, the proven and probable (2P) reserves were estimated to be 26.8 million barrels (MMbbls). With the outstanding performance of the fields and the assessment of new information from the production process, this initial reserve figure has been upgraded several times and is currently 50.1 mmbbls. With 20 mmbbls produced to date, remaining 2P reserves are approximately 30 mmbbls- meaning that the estimated amount of recoverable oil remaining is still higher than the original total 2P reserve figure. The oil is produced from four wells through a floating production, storage and offloading vessel (FPSO), the Umuroa. The oil is shipped by tanker to refineries in Australia and south-east Asia. There have also been several shipments Hawaii.

Petrobras to invest $4 bn to produce S-50 diesel

January 13, 2009. Brazilian state-run energy giant Petroleo Brasileiro (PBR) will invest $4 billion through 2012 to produce reduced-sulfur diesel. The company's Duque de Caxias refinery was currently testing treatment units to produce so-called S-50 diesel fuel. The diesel contains sulfur at 50 parts per million. Petrobras started supplying metropolitan bus fleets in Sao Paulo and Rio de Janeiro with S-50 diesel. Petrobras imported the first few months supply of the lower-sulfur diesel while it converts local refinery output. An additional $2 billion will be invested at Petrobras' refineries to convert to production of even-cleaner-burning S-10 diesel. The S-10 diesel fuel will be produced starting in 2013.

BP to supply up to 70,000 bpd to Vietnam refinery

January 13, 2009. BP Plc will supply Petrovietnam with up to 70,000 barrels per day (bpd) of foreign crude for the country's new Dung Quat refinery, which needs to invest another $1 billion to upgrade to process lower-quality crudes by 2011. Under a contract signed, BP would supply sour crude oil to replace Vietnam's flagship Bach Ho grade, now used as the only feedstock to the 140,000-bpd Dung Quat refinery. The signing of the contract opened a new direction for the refining industry in Vietnam and would make an important contribution to meet demand from the domestic market, which now relies 100 percent on product imports. Petrovietnam would have to invest up to $1 billion to add a "desulphuriser component" to enable it to process sour, or high sulphur, crude at the refinery that is slated to come onstream on Feb. 25 after more than a decade of planning. The complex already costs $2.5 billion to build. Petrovietnam's crude trading arm PV Oil, Nguyen Quoc Khanh said, the refinery would only need to import foreign crude oil from 2011. In the meantime, BP could also supply sweet crude to the refinery if the imported grade is cheaper than, but similar to, the domestic Bach Ho crude. BP is already a major investor in Vietnam and is operator in Vietnam's biggest natural gas pipeline, the $1.3 billion Nam Con Son project. It is a major producer of West African and North Sea crudes and also produces Middle East and Asia Pacific grades. Petrovietnam-owned Binh Son Refining and Petrochemical Company Ltd, which runs Dung Quat, had previously said the refinery was designed to either process Vietnam's flagship light sweet Bach Ho crude or a mixture of 85 percent of Bach Ho and 15 percent Dubai crude. Under the engineering agreement with the refinery's builder, Technip, Dung Quat would use exclusively Bach Ho in 2009. But shrinking output from the ageing Bach Ho field, which now churns out about 150,000 bpd, is forcing Petrovietnam to seek alternative crudes to ensure stable future feedstock to Dung Quat. In 2007, Petrovietnam also clinched two separate preliminary agreements with oil traders Glencore and Trafigura to study the possibilities of using foreign sour crude for Dung Quat. Traders in Singapore said it would make sense for Petrovietnam to sell high-quality, more expensive Vietnamese crudes and import cheaper Middle Eastern grades for refining.

Other traders added it could also buy sweet crude from West Africa and Asia Pacific depending on prices, at a time when demand and prices for such sweet grades lag that of sour Middle Eastern grades. Petrovietnam test-ran the $2.5 billion refinery from December at about 30,000-bpd capacity. The plant will run at its full capacity of 140,000 bpd from the fourth quarter this year, meeting about 30-40 percent of the country's total consumption. Petrovietnam said the group would sell up to a 49 percent stake in the refinery to foreign investors who could guarantee secure crude supply. So far no foreign companies, including BP, have expressed interest in Dung Quat, mainly on concerns over the refinery's location far from two main consumption centres in Ho Chi Minh City and Hanoi.

Last year Petrovietnam secured a $6 billion joint-venture contract for its second refinery, the 200,000-bpd Nghi Son plant, with Japanese refiner Idemitsu Kosan Co and Kuwait Petroleum International. The plant will use 100 percent crude imported from the Middle East, Petrovietnam has said. It is also holding talks with foreign companies including Venezuela's national oil company PVDSA for a third refinery in Long Son in southern Ba Ria Vung Tau province, as it moved to become self-sufficient in oil products by 2015 when the three refineries are up and running.

Pertamina offers to acquire stake in Masela project

January 13, 2009. Indonesia's state-owned oil and gas company PT Pertamina said it has offered to acquire 30% stake in the Masela gas block, which is fully controlled by Japanese contractor Inpex. Pertamina has set aside fund for the acquisition of the stake in the Masela project which is estimated to cost more than $19 billion including for a floating LNG plant. PT Shell Indonesia has also indicated interest in the venture suggesting participation in the construction of the floating LNG plant.

Pertamina and Shell have signed a memorandum of understanding to develop technology for floating LNG plant. The agreement is not particularly intended to build floating LNG plant in Masela although Shell and Pertamina have approached Inpex for possible participation in the project. Recently Inpex chairman Kunihiko Matsuo announced plan to sell part of its shares in Abadi gas field in the Masela block on credit crunch.

Tulsa refinery may become terminal

January 13, 2009. Sunoco Inc.'s west Tulsa refinery could sell for $500 million, but market conditions and environmental challenges might force the company to convert it into a terminal by the end of this year. Sunoco is still looking for a buyer and has talked to a number of interested parties since December 2007. The refinery can produce about 85,000 barrels per day, reports say. Falling gasoline prices forced the company last year to cancel a $375 million project to upgrade the quality of the diesel fuel it produces. Sunoco also faces the same economic challenges that so far have prevented Valero Energy Corp. of San Antonio from selling two Mid-Continent refineries that it put on the market, reports show. Sunoco signed off on a federal consent decree committing it to spend $28 million on emissions reduction at the refinery. Stricter EPA sulfur limits also have forced the company to spend hundreds of millions of dollars at various refineries. The refinery employs about 375 people and primarily produces diesel fuel and lubricants. The refinery was acquired 41 years ago by Sunray DX, which later merged with Sun Oil Co., a forerunner of Sunoco Inc.

Iraqi identifies refinery contractors

January 12, 2009. Technip SA, Stone & Webster Inc. and Foster Wheeler Ltd. won contracts to design four refineries in Iraq as the country works to end fuel shortages. Foster Wheeler Inc. won a contract to design the Nassiriya refinery, Technip the Kerbala plant and Stone & Webster two refineries in northern and southern Iraq. It could take these companies nearly two years to finish designs of these refineries. Iraq wants to build a large refinery in central Iraq at Hindeyah near the highway between Kerbala and Najaf, south of Baghdad, with 140,000 barrels a day processing capacity. It also plans to build the Nasiriya refinery, near the city of Nasiriya in southern Iraq, to process 300,000 barrels a day to address an acute fuel shortage in Iraq. A third refinery is planned in the oil-rich Kirkuk province with 150,000 barrels a day processing capacity. The last one is planned in the Missan province to produce 150,000 barrels a day. Iraq's new refineries, which will take several years to build, are expected to boost the country's fuel production and counter crippling gasoline and other fuel products shortages. Iraq boasts the world's third-largest known reserves of oil but decades of wars, sanctions, underinvestment and violence and sabotage have left the country critically short of fuel. It now imports more than a quarter of its gasoline needs. Iraq's existing large three refineries in Baiji, Baghdad and Basra, are operating only at half their capacities, forcing the country to import fuel at millions of dollars a month.

Mitsubishi to acquire stake in Kitimat LNG

January 13, 2009. Kitimat LNG Inc. and Mitsubishi Corp. have signed a Heads of Agreement under which Mitsubishi will acquire terminal capacity and an equity stake in Kitimat LNG's proposed liquefied natural gas (LNG) export terminal. The Heads of Agreement sets forth the terms, pursuant to which Mitsubishi will commit to purchase 1.5 million tons per annum (mtpa) of terminal capacity and acquire a minority equity interest in Kitimat LNG's 5.0 mtpa project in Kitimat, B.C. The transaction is expected to be finalized and closed by March 31, 2009. Kitimat LNG is continuing a process for interested parties to participate in equity investment, terminal capacity use, and off-take in the project. Kitimat LNG and Mitsubishi look forward to participation by other strategic partners to join this project. Kitimat LNG received Canadian Federal Government approval for its liquefaction terminal on December 10, 2008 and B.C. Provincial Government approval on January 9, 2009. The Kitimat LNG project will utilize natural gas transported via pipeline from Western Canada to the Kitimat LNG Terminal. At the terminal, the natural gas will be liquefied for export via ship to the growing Asian energy markets. The Kitimat LNG terminal will be the only LNG export facility in North America since the Alaskan LNG liquefaction plant began operation in 1969.

Russia set to resume gas supplies to Europe

January 12, 2009. Russia should resume gas supplies to Europe via Ukraine, European Union said after a deal on an international gas monitoring team appeared to have been sealed in Brussels. Under an eagerly awaited deal that had to be signed twice within the space of a few days, 25 experts from the European Union, Ukraine and Russia are to monitor gas flows at compressor stations in both Ukraine and Russia and at another three stations in Slovakia and Romania. The deployment of the international monitoring mission, which is designed to look into Russian allegations that Ukraine has been siphoning off Gazprom gas destined to its European clients, is already underway. The mission has been prompted by an increasingly bitter commercial dispute between Russia and Ukraine's Naftogaz that has caused a 30 per cent drop in gas supplies to Europe amid freezing winter temperatures. Experts say that once the taps are turned back on, it should take about three days for gas from Siberia to transit through Ukraine and reach clients in the EU. But experts note that a series of divisive issues still need to be addressed before the dispute can be fully resolved. These concern payments for gas needed to raise pressure in Ukraine's pipeline system after the embargo ends, Ukraine's possible obligation to Russia of 614 million dollars in late payment fines, Russia's possible obligation to Ukraine for gas supplied to Bulgaria and Moldova, and how long the EU observer mission will operate in Ukraine. The monitoring deal is also silent on the underlying cause of the gas crisis: the absence of a contract between Gazprom and Naftogaz for natural gas deliveries and onward transportation to Europe. At least 12 EU states and five EU neighbours have been hard hit by gas shortages since Gazprom turned off all supplies to and through Ukraine - the main transit route for Russian gas heading to Europe. EU newcomer Bulgaria has seen its gas supplies cut off entirely and stocks all but exhausted, while neighbouring Serbia has been left relying on emergency transfers from Hungary and Germany. Russia says Gazprom has lost some 800 million dollars as a result of its row with Ukraine.

CB&I wins LNG expansion project in China

January 8, 2009. CB&I has been awarded a contract for an LNG import terminal expansion project in Fujian Province, China, by CNOOC Fujian LNG Co. Ltd. The contract value is confidential. CB&I's scope of work includes engineering, procurement and construction of two additional 160,000 cubic meter full containment LNG storage tanks. The project is scheduled to be completed in 2011. The initial phase of the LNG terminal, which has a capacity of 2.6 million tonnes of LNG per year and includes two 160,000 cubic meter LNG storage tanks, received first gas in April 2008. The U.S. Energy Information Administration forecasts that China's natural gas demand will grow 6.4% per year between 2010 and 2020. By 2020, about 25% of China's natural gas demand is forecasted to be met through LNG imports. CNOOC Fujian LNG Co. Ltd. is a co-investment of China National Offshore Oil Corporation (CNOOC) and Fujian Investment and Development Corporation.

Baltic gas terminal to be ready in 2013

January 13, 2009. Special legislation to facilitate the construction of an LNG terminal in Swinoujscie harbour on the Baltic will be adopted by the cabinet by the end of next month. The government wants the legislation to take effect in early May 2009. This will make it possible to finish the construction of the terminal by 2013 at the latest. Last August, the government labelled the project "strategic" and later a special company to build the terminal was set up, wholly owned by Gaz-System, a state-owned company. The terminal will receive 2.5bn cu.m. of natural gas in the early stage and help increase Poland's energy security.

‘Croatia to discuss LNG project with Qatar’: PM

January 12, 2009. Croatian Prime Minister Ivo Sanader said the government would discuss the possibility of Qatar building a Liquefied Natural Gas (LNG) terminal in Croatia with its partners in the consortium for the construction of the terminal in Omisalj. He said there was also an idea to build a terminal in Ploce as well, in which Bosnian Presidency member Haris Silajdzic recently expressed an interest. He said that (Hungary's oil company) MOL, too, is interested, not only via (Croatian oil and gas company) INA but also as a separate company. Sanader stressed that Croatia was also interested in Bosnia and Hercegovina's energy independence. He confirmed that a new underground gas storage facility would be built, primarily for Croatia's needs, but in which other countries in the region would be able to store gas too.

Sudan to discuss refinery plans with Petronas

January 12, 2009. Sudan and Malaysia's state oil company Petronas are scheduled to meet in March to discuss plans for a delayed joint venture refinery project. Last June, Petronas had deferred plans to build the 100,000 barrels per day refinery in the African country due to rising costs, estimated to have jumped to about $5 billion from $1-$2 billion when it was first planned.

Equipment and labor shortages have pushed costs up globally in the energy sector, leading to several refining projects being delayed or cancelled. Petronas signed a deal in August 2005 to invest in the refinery, which would process some of the hard-to-sell, high acidic Dar Blend crude. Sudan, where Petronas is a major investor and has equity in the Nile Blend and Dar Blend oilfields, faces U.S. economic sanctions to press for an end to the conflict in the Darfur region.

Abu Dhabi's IPIC delays Pakistan refinery plans

January 12, 2009. Abu Dhabi government-owned International Petroleum Investment Company has delayed plans to set up Khalifa Point refinery in Pakistan and is reviewing its Fujairah refinery project. IPIC also plans to invest $70 billion over three phases in Abu Dhabi's petrochemical industry and may increase its stake in Austrian energy firm OMV and Spain's Cepsa after finalising a deal to buy 70 percent of industrial services firm MAN Ferrostaal AG, part of German group MAN. IPIC invests in oil-related projects for the government of Abu Dhabi, the capital of the United Arab Emirates, which is the world's fifth-largest oil exporter. Its board approved last year plans to build a $5 billion refinery with a capacity of 250,000 barrels per day (bpd) in Pakistan. A planned $6-7 billion refinery with capacity of 500,00 bpd in Fujairah in the UAE is also likely to be delayed.

But a 370 km (229.9 mile) crude oil pipeline from Abu Dhabi to Fujairah is on track for completion by early 2010. It will carry 1.5 million bpd of crude for export from Fujairah. The storage terminal at Fujairah will have capacity of up to 12 million barrels. A new joint venture company Chemaweyaat, in which IPIC is a 40 percent shareholder, plans to invest at least 70 billion dollars in petrochemicals in Abu Dhabi. In the first phase, $20 billion will be invested and more than $50 billion will be invested in the second and third phases.

Abu Dhabi Investment Council holds 40 percent and ADNOC holds 20 percent stakes in Chemaweyaat. IPIC also plans to invest up to $2 billion in the Caspian Sea region in various sectors and will involve MAN Ferrostaal in these projects. IPIC's investment portfolio currently stands at between $12 to $15 billion but it is poised to increase as it seeks new and diversified investments.

Ecuador suspends output of foreign oil firms to comply with OPEC cuts

January 9, 2009. The Ecuadorian government has decided to suspend oil production by Italy's Agip (24,000 bpd) and France's Perenco (7,000 bpd), both of which operate in the Amazon region, to comply with new OPEC cuts. The two firms produce a combined 31,000 barrels per day of crude, which is less than the 44,000 bpd cut for Ecuador mandated by OPEC, of which Ecuador is a member. The Mines and Petroleum Ministry of Ecuador is to take until next week to determine what further cuts will be made to comply with OPEC's decision. OPEC on Dec. 17 agreed to cut joint production by 2.2. million barrels in an attempt to stabilize international crude prices, which have plunged more than 70 percent from record highs last summer. The Ministry said, due to the sharp price drop, it is more costly for the country to develop several oil fields than it is to suspend production on them. On Dec. 27, Ecuadorian President Rafael Correa said his government would order a reduction in output by foreign companies to comply with the production cuts agreed to by OPEC. Oil is Ecuador's main export, and the Andean nation currently produces around 500,000 barrels per day of crude, of which state-owned Petroecuador accounts for just under 40 percent. Revenue from oil exports finances roughly 35 percent of Ecuador's public spending.

Iraq earns $60 bn from 2008 oil exports

January 7, 2009. As per the Iraq's State Oil Marketing Organization, or SOMO, the country’s crude oil exports averaged 1.85 million barrels a day in 2008, some 13.5% more than in 2007. Iraq's revenues from crude oil sales in 2008 reached around $60 billion, or 33.6% more than in 2007. The increase in oil revenues was helped by a surge in oil prices and an anticipated rise in exports at the beginning of 2008 that helped offset the sharp decrease in the market from a record high of $147 a barrel in July to as low as $36.94 a barrel in the last week of December.

POWER

SA’s next nuclear power plant to come on stream by 2019

January 13, 2009. South Africa expects its next nuclear power plant to come on stream by 2019, two years later than initially planned by Eskom, which has dropped plans to build the facility due to financial woes. While Eskom was hoping nuclear energy would supply one quarter or 20000 megawatts (MW) of South Africa's expanded generating capacity by 2025, the government says a target of 6000 MW in the same period is more feasible. South Africa will have to keep reverting to more coal to supply its growing demand in the meantime. South Africa's power utility operates Africa's sole nuclear power plant, Koeberg, with a total capacity of 1 800 MW. An additional 3200 MW of the planned 6 000 MW was due in 2019. South Africa would approach various countries that have made nuclear part of their energy mix to copy their models. These countries include France, Britain, the US, South Korea and Russia. Nuclear is a major part of South Africa's energy diversification plan to cut its reliance on coal, which now supplies the lion's share of electricity. The government would revise its nuclear plans, taking into account the economic slowdown. But the cost, coupled with the long lead time of between seven and 10 years to build a new nuclear plant, means South Africa will have to pump up its coal production in the meantime, even though that will harm the country's ambition of drastically reducing its carbon footprint. South Africa's progress on renewable energy has also been slow, hindered by financial constraints, as well as the limited amount of energy that they produce.

Doubts about Maytas' hydropower bids in Nepal

January 9, 2009. Maytas Infra, one of its chief promoters Satyam owned up to a colossal corporate fraud, has made a bid for a 110 MW hydropower project on the Budi-Gandaki Arket river in western Nepal's Gorkha district. Along with Maytas Infra, its unlisted real estate wing Maytas Properties, has applied for the 102 MW Dudhkoshi 2 hydropower project in northern Solukhumbu district. The bids were made on the same day around two years ago when Satyam's fortunes were soaring. However, with hydropower being one of the slowest moving sectors in Nepal, the water resources ministry sat on the applications. The political uncertainty in the country also added to the delay. Now ironically, as Satyam tarnished its halo, the Nepal ministry has decided to begin screening the applications. However, the good news for the two Maytas firms is that Nepal, preoccupied with its own woes - that includes a daily 12-hour power outage and the closing down of industries by militant trade unions - has not followed the vicissitudes in their fortunes. The water resources ministry has decided to move projects around 100 MW. It would soon ask the bidders to furnish the additional documents it needs within two months. There are no other contenders for the two projects that the Maytas have been eyeing in Nepal. However, with the Satyam exposure having created panic, it now remains to be seen if the two Maytas companies would be ready to go ahead with new ventures in a foreign country, especially one as volatile as Nepal.

Texas cities cut their power bills

January 13, 2009. More than 100 Texas municipalities, including several in Tarrant County, expect to cut their annual electricity bill by at least $30 million this year under the terms of a new five-year contract with Direct Energy and FPL Energy. Cities Aggregation Power Project member cities will pay between 5 cents and 8 cents per kilowatt-hour for power, plus distribution and administrative charges, depending on their location. West Texas enjoys the lowest power prices, thanks to a surplus of wind power there, while Houston and South Texas typically have the highest prices. North Texas cities in the project include Arlington, Grapevine and North Richland Hills. They paid about 10.5 cents per kwh on average for their power last year. About 50 smaller communities in another group, the South Texas Aggregation Project, will buy their electricity under similar terms. By contracting now, CAPP members are able to take full advantage of the dip in energy prices that occurred in the latter half of 2008. Those prices are generally locked in through 2014. Natural gas is a major component in electricity generation. The contract with Direct Energy and FPL Energy, which went into effect Jan. 1, replaces a previously negotiated deal with Luminant Generation that was announced in September. That pact offered exceptionally low power costs and was intended to last 24 years, but it required participants to issue long-term bonds to help Luminant finance some of its operations. Luminant is the power-generating operation of Dallas-based Energy Future Holdings, formerly TXU Corp. Only about 40 project members voted to participate in the Luminant contract. Their electrical load was much less than Luminant had hoped to supply. The ongoing financial crisis created too much uncertainty for such a long-term contract. Under the new contract, project members agree to buy all their electricity for their own operations from Florida-based FPL Energy. Direct Energy will handle billing and administration. While FPL is Texas’ and the nation’s biggest generator of wind power, the project contract does not include a specific quota for wind.

Nepalese to get only 8 hours electricity daily

January 11, 2009. Nepalese citizens will be allowed only eight hours of electricity a day because of low water levels in reservoirs that drive hydroelectric plants. The government-owned Nepal Electricity Authority announced citizens will face 16-hour power outages daily until the situation improves. The state utility imposed 12-hour power cuts each day just last month but increased blackout hours because of the worsening power crisis. Nepal's government is planning to install expensive diesel-powered plants. The Association of Private Health Institutions warned Sunday it would soon reduce services because it cannot afford to run generators for so long. Private television stations in Nepal have announced several hours of cuts to regular broadcasts, citing growing power outages. Television Broadcasters’ Nepal, an umbrella body of five private stations, said they would no longer be able to keep up round-the-clock broadcasts due to power outages. Electricity production had fallen to just a quarter of the demand because of low water levels in reservoirs and rivers that feed the country’s hydroelectricity plants, according to the NEA. Nepal produces only about half its electricity needs, in part because of unusually low levels this year in reservoirs that feed the country's hydroelectric plants. The amount of power that Nepal imports from neighboring India is not enough to make up the shortfall. But floods in the Kosi river in September washed away the main transmission lines used for importing power from India. Construction of new power plants was hampered by a decade-long communist insurgency that ended in 2006.

Vietnam mulls raising electricity prices

January 13, 2009. Vietnam will likely raise retail electricity prices by up to 10 percent this year to attract more investment in the energy sector, which is struggling to meet booming demand. As per the Ministry of Industry and Trade, Vietnam's electricity prices are much lower than those elsewhere in the region, making it less attractive to potential investors. The ministry recommended the price increase last month, but it will not take effect unless it is approved by Prime Minister. Vietnam charges households 862 dong (4.9 U.S. cents) per kilowatt hour, while manufacturers pay 900 dong (5.2 cents). Thailand, Singapore, Indonesia and Malaysia charge from 14 cents to 15 cents, according to Electricity of Vietnam or EVN, the country's power company. In neighboring China, the top price is 7.5 cents per kilowatt hour. Vietnam's demand for power is expected to grow by 16 percent a year until 2015, according to government projections, and the country's booming economy has made it difficult for supply to keep pace with demand. Vietnam's economy grew 8.5 percent in 2007 and 6.2 percent last year, despite the global economic slowdown. Its growth rate is among the fastest in Asia. More than 500,000 families who use less than 50 kilowatts per hour a month will not be affected by the price increase because of government subsidies.

‘Electricity tariffs should go down’: Trade Ministry

January 12, 2009.  Electricity tariffs should be reviewed now that international fuel prices have plummeted, said International Trade and Industry Ministry of Malaysia. The ministry would hold discussions with Petronas, TNB and the Water, Energy and Communications Ministry on the matter. TNB has said that its new tariff structure which took effect on July 1 last year was not dependent on oil prices but on that of gas and coal prices. Energy, Water and Communications Ministry had earlier said that tariff could not be reduced for now although the price of oil has come down, adding that peninsular Malaysia, electricity was generated mostly by using gas and coal, and not oil. The three main sources to generate electricity in the peninsula is 60% gas, 30% coal and 6% to 7% hydro power with the rest from other sources.

EU warns Slovakia on nuclear plant restart

January 12, 2009. The European Union would take action against Slovakia if it restarts a Soviet-era nuclear reactor to cope with a gas shortage caused by the dispute between Ukraine and Russia. Under EU pressure, several eastern European nations have been forced to close atomic power plants that don't meet modern safety standards, making them rely more on imported Russian gas. As per the Slovakian Energy Minister, the Jaslovske Bohunice nuclear plant would restart to compensate for the loss of Russian gas - even though supplies will be restored within days. The Slovak plant would stay running until the country had refilled its gas storage capacity. The shutting down of the old reactor in the Jaslovske Bohunice nuclear plant was a condition for Slovakia joining the EU in 2004. The European Commission said it was helping Slovakia deal with energy shortages and warned it would be a "serious violation" if the nuclear plant reopened. Russia shut down its natural gas pipeline to Europe last week amid a dispute with neighboring Ukraine, but has promised to restart supplies early. Slovakia depends on Russian gas to keep its citizens warm during the freezing winter. It declared a state of emergency last week, ordering 1,000 companies to reduce consumption and keep gas for homes, hospitals and schools. The nuclear plant used to generate a fifth of the country's electricity. The last reactor shut down Dec. 31 under EU pressure. Another reactor at the power station was shut down in 2006.

Tata Power signs MoU with Gujarat

January 12, 2009. Tata Power Company Limited, signed a Memorandum of Understanding (MoU) with Government of Gujarat to explore the possibility of setting up a 5 MW Geothermal Power Plant in phase I, at a suitable location in Gujarat. The company also signed an MoU for developing a 5 MW solar power plant in Gujarat. Geothermal energy is the natural heat found within the earth, where temperature increases with depth, typically by 10-50 degree Celsius/km. In Enhanced Geothermal Systems (EGS) technology, heat is extracted from granites located at a depth of a more than 4000 metres by circulating water through them in an engineered artificial reservoir. The heated water returns to the surface under pressure and is converted into electricity via a heat exchanger and conventional geothermal power plant. Tata Power’s presence in solar includes “Tata BP Solar India Ltd.” a Joint-Venture with BP Solar, one of the largest solar companies in the world. Tata BP Solar is a market leader in Solar Photovoltaic technology in India with a turnover of Rs 6.60 bn. Nearly 75% of its sales come from exports largely to Europe and USA. Its growth plans include expansion of its module manufacturing facility and thrust on domestic sales.

MoUs of Rs 1 trillion for renewable energy sector

January 12, 2009. Renewable energy sector received a boost at Vibrant Gujarat Global Investors Summit when as many as 67 MoUs were inked for setting up power plants related to solar and wind energy. Sector-wise, highest number of MoUs (67) were signed in the renewable energy sector, envisaging a total capital investment of more than Rs one lakh crore. MoUs have been signed for projects based on solar and wind energy generation of more than 9,000 MW. Wind energy major Suzlon inked an MoU for setting up world's largest greenfield wind farm of 1,500 MW in Kutch district. Suzlon Group has lined up investments of around Rs 9,000 crore in Gujarat. Gujarat State Petroleum Corporation (GSPC) also signed an agreement for developing a 200 MW wind farm power plant in the state.

Suryachakra Power’s arm inks pact with MSEDCL

January 9, 2009. Sri Panchajanya Power Pvt. Ltd, one of subsidiary Companies of Suryachakra Power Corporation Ltd, is setting up of 10 MW Biomass Power Project at MIDC, Hingoli, Maharashtra State. In addition to this Sri Panchajanya Power Pvt. Ltd has signed Power Purchase Agreement (PPA) with Maharashtra State Electricity Distribution Company Ltd (MSEDCL) on January 07, 2009 for setting up of 5 MW concentrated Solar Thermal Power Project at Hingoli, Maharashtra and the Company has already submitted required papers with Ministry of New and renewable Energy for registration to get generating subsidiary.

Gujarat invites investment in wind power sector

January 8, 2009. The Gujarat Government has invited investment in the wind power sector with an aim to increase wind power generation in the State. The Government has targeted 10 per cent of the total energy sold from renewable sources and proposed an increase in power purchase rate to Rs 3.50 a unit from Rs 3.37 a unit. The State plans to give impetus to research and development and manpower development in wind power in energy management curriculums. The State has enhanced the renewable purchase obligation in the amendment to the new wind power policy. It states that each distribution licensee shall purchase electricity generated from all renewable energy sources equivalent to a minimum of 10 per cent of its total electricity sold during the year and will develop a mechanism for issuance of renewable energy certificates, a market based tradable instrument will be developed.

Gujarat announces solar power policy

January 7, 2009.  To promote green and clean power in the State, the Gujarat Government is giving a thrust to solar power generation, offering a number of incentives under its new solar energy policy. The Government would also put in place an appropriate investment climate leveraging the carbon trading mechanism (CDM) and conserve the State’s natural carbon energy resources and transform it into an “integrated solar generation hub” of the country. Announcing the new Solar Energy policy 2009-14, the Minister of State for Industry, Mr Saurabh Patel, said initially, the Government would provide incentives to those installing a minimum SPG capacity of 5 MW in case of solar photovoltaic or solar thermal means. Solar power generators installed and commissioned during the operative period of this policy (2009-14) would be eligible for incentives. Electricity generated from the SPGs for self-consumption or sale to licensees or third parties shall be exempted from payment of electricity duty. The energy generated from a solar power project shall be sold to the distribution licensees in Gujarat at levelised fixed tariff per unit for a period of 25 years under a power purchase agreement.

Massachusetts sets 10 pc of electricity from wind by ’20

January 13, 2009. Massachusetts set an aggressive target of generating enough electricity from wind to power 10 percent of its needs, or about 800,000 homes, by 2020. That would require installing enough wind turbines to produce 2,000 megawatts of power, compared to just 6.6 megawatts now. There are currently proposals in the works to install another 300 wind turbines, which would boost the state's capacity by 800 megawatts. Foremost among them is the Cape Wind project, which would place some 130 turbines, each 247 feet tall, off the shore of the Cape Cod resort area. Major producers of wind turbines include Denmark's Vestas Wind Systems A/S, U.S. conglomerate General Electric Co and German engineering group Siemens AG.

AEDB to help set up 10 MW renewable energy plant

January 13, 2009. An American firm Sheladia would undertake a viability study for generation of up to 10 megawatts (MW) of electricity from solid waste in Karachi under a US-funded project. The agreement will not only expand electricity production sources, but would also make modest contribution to reducing the energy deficit facing the country. Funds for the study would be channeled through Alternative Energy Development Board (AEDB), the focal point for promotion of renewable energy resources in the country. An agreement to this effect would be formally inked between Sheladia and AEDB. The firm plans to commence the $325,000 project shortly, which would be concluded in about five months. It has been asked to complete the waste management study, defining the best options for converting it to energy and preparing required tender documents for the power plant. The plant will then be set up under public-private partnership. It will be the first study of its kind and the project when implemented will become a model waste to energy project for other cities to follow. AEDB was working on expeditious development of renewable energy resources in the country and the First commercial wind farm established by M/s Zorlu would be inaugurated in about two weeks.

Solar power plants to spring up in China

January 13, 2009. Two large solar power plants will be built in the western plateau provinces of Qinghai and Yunnan in 2009, with the expectation for China to cut domestic reliance on coal and oil. The Qinghai project, a gigawatt-level solar station, will begin the first phase construction in 2009. The plant was funded by an initial investment of 1 billion yuan ($146 million). It could become the world's largest when completed. The NASDAQ-listed China Technology Development Group Corp. and the privately-owned Qinghai New Energy Group are overseeing the design, construction, installation and operation of the station. The government of Haixi Autonomous Prefecture of Mongolia and Tibet nationalities, where the project is located, signed an agreement with the two companies to help them acquire land, subsidies and project approvals from the central government. Roughly a month ago, the southwestern Yunnan Province announced it would begin construction of a 166-megawatt solar plant with an investment of 9.1 billion yuan -- the largest in China at the time of the announcement. Statistics from the China Renewable Energy Society showed more than two thirds of China's land receives more than 2,200 hours sunshine annually, more than many other regions of similar latitude such as Europe and Japan, which gives China a potential solar energy reserve equivalent to 1,700 billion tons of coal. China is now the world's largest producer of solar heaters and the third largest manufacturer of photovoltaic cells, the National Development and Reform Commission (NDRC) statistics show.

GE, China-based power firm enter wind power deal

January 12, 2009. A General Electric Co. subsidiary and China-based A-Power Energy Generation Systems Ltd. signed two letters of intent, one for a supply deal and a second for a joint venture partnership. Under the supply agreement, GE Drivetrain Technologies will provide A-Power with more than 900 2.7 megawatt wind turbine gearboxes starting in 2010. The companies intend to establish a joint venture partnership for a wind turbine gearbox assembly plant that will be majority owned by GE Drivetrain, as it tries to expand into global markets, and that will capitalize on A-Power's local market knowledge.

Obama doubles renewable energy tax credit in stimulus plan

January 12, 2009. Energy producers may soon notice the decided shift in the wind in Washington, political and otherwise. After consulting with Congressional Democrats, President-elect Barack Obama moved quickly to double his proposed tax credit for renewable energy in his fiscal stimulus package to $20 billion. The Obama Administration's overall fiscal stimulus package is expected to total about $700-$850 billion. Congressional Dems wanted a renewable energy tax credit program that will help speed the development of solar and wind power, and $20 billion in 2009 will further that goal. Energy policy provides "a good snapshot of Obama's pragmatic, best-elements policy stance". Doubling the renewable energy tax credit will assist research and development of these important 21st century energy sources, and will create many good-paying, domestic jobs.

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