Afroil - Africa Oil & Gas Monitor

Top story from 31 January 2012, Week 04 Issue 424

Heritage heading for Tanzanian frontier

Heritage Oil has been awarded the Kyela production-sharing agreement (PSA) covering the entire northern onshore portion of Tanzania’s Lake Nyasa Basin, an area that has not yet been explored for hydrocarbons.

Although frontier territory, gravity data covering the 1,934-square km PSA suggests “a sedimentary section of sufficient thickness to allow for the generation of oil,” which is supported by historical seismic data from the adjacent Lake Nyasa, Heritage said in a statement dated January 25.

Work is due to start soon on a high resolution gravity survey to determine sediment thickness distribution and delineate any structural trends that could indicate hydrocarbon traps, taking in around 1,500 square km of the PSA. A 2-D reconnaissance seismic programme will follow, based on the results.

It is thought the Kyela PSA may share some geological similarities with Tanzania’s Rukwa PSA, which was awarded to Heritage in November 2011, as well as with Uganda’s prolific Albert Basin.

“Our expertise, both technical and operational, on rift basins will provide Heritage with a key advantage in assessing the prospectivity of both new awards,” Heritage’s CEO, Tony Buckingham, said. “We look forward to commencing the work programme in Tanzania over the next few months.”

If oil is discovered at one or both PSAs, Heritage has two options for export, dependent upon the success of the exploration. One involves using the railhead at Mbeya – which lies around 125 km from the Kyela PSA and is less than 100 km from the PSA at Rukwa – to transport oil to the Tanzanian capital Dar es Salaam. Alternatively, plugging into a pipeline is also a possibility.

The independent, headquartered in Jersey, Channel Islands, was awarded 100% interest and operatorship of both the Kyela and Rukwa PSAs.

Heritage also has African exploration projects in the Democratic Republic of Congo (Kinshasa) and Mali, as well as an investment in Libya.

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 Asia Oil & Gas Monitor

Top story from 01 February 2012, Week 04 Issue 310

Indonesia’s Pertamina plans to boost capex in 2012 by 40%

Indonesian state oil firm Pertamina has said it will increase capital expenditure by 40% in 2012 as the government seeks ways of boosting oil and gas production.

Pertamina said it would spend almost US$6 billion, mostly in the domestic upstream sector. The firm will buy new oil and gas blocks within Indonesia and invest in infrastructure, as well as making upgrades to some refining facilities, said spokesman Mochamad Harun in a statement last week.

There will be two new oil projects off Java Island’s west coast and numerous exploratory wells will be drilled elsewhere in domestic offshore blocks, he said.

Indonesia failed for the third year running in 2011 to meet government oil and gas production targets, and although it is one of the world’s top three liquefied natural gas (LNG) exporters, it suffered a gas shortage which forced power plants to shut down for long periods.

Indonesia is also suffering from inadequate pipeline infrastructure.

“The government’s objective is to raise oil production back to 1 million barrels [per] day, which is something it hasn’t achieved since it ceased to be a member of OPEC after becoming a net importer,” Bangkok-based analyst Sar Watana told AsianOil.

Indonesia produced just 903,400 bpd in 2011, against a government target of 945,000 bpd, state regulator BPMigas disclosed in January.

Originally, the government had called for 970,000 bpd for 2011 but by mid-year most oil producers operating in the country had persuaded Jakarta that figure was unrealistic.

“It is unlikely that Pertamina will be able to boost oil production significantly this year but its investment plans could lead to higher output by 2014,” Watana explained.

Indonesia’s oil production peaked at 1.6 million bpd in the mid-1990s but has been declining since. Indonesia’s OPEC membership ended in 2008.

The decline has been blamed by major foreign producers operating in the country, such as Chevron and Total, on a poor investment climate, in part caused by bureaucracy.

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 China Oil & Gas Monitor

Top story from 02 February 2012, Week 04 Issue 379

ConocoPhillips, CNOOC agree to US$160m oil spill payout

US firm ConocoPhillips and its partner China National Offshore Oil Corp. (CNOOC) have agreed to pay the equivalent of about US$160 million in compensation to fishing communities afflicted by oil spills in Bohai Bay off China’s northeast coast in 2011.

The money will settle a slew of claims made by various fishing groups who alleged that their livelihoods and fishing grounds were damaged.

ConocoPhillips also said last week that it would pay US$16 million into its previously announced environmental fund to help regenerate and improve fishing resources in spill-affected areas.

CNOOC is to donate about US$40 million for similar fisheries aid, said the official news agency Xinhua. It has not been clarified how much of the US$160 million each of the two oil firms will pay.

Leaks from two platforms of the Penglai 19-3 oilfield in June 2011 polluted more than 6,000 square km of Bohai Bay, according to State Oceanic Administration (SOA), which accused operator ConocoPhillips of negligence.

The US firm is operator of the 168,000 barrel per day field with a 49% share.

The compensation appears to more than cover claims totalling about US$78 million, which were brought against ConocoPhillips and CNOOC at the end of 2011.

In January, CNOOC announced it would contribute US$80 million towards the establishment and operation of a new state marine protection agency, the Marine Environmental Ecological Protection Public Welfare Foundation.

One of the main briefs of the agency would be to develop treatment techniques for tackling any future oil spills, said CNOOC.

The Penglai field was shut down in September 2011.

ConocoPhillips last week described itself as a “responsible corporate citizen in China”, committed to what it termed environmental stewardship.

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 Downstream Monitor MENA

Top story from 01 February 2012, Week 04 Issue 41

KBR awarded contract for Aswan plant

Houston-based Kellogg Brown and Root (KBR) has been awarded a sub-contract for the supply of its proprietary process technology and to carry out basic design studies for a new petrochemical plant to be built at Aswan in Egypt.

The order – whose value is unknown – was placed by Italy’s Tecnimont, which is acting as the main engineering, procurement and construction (EPC) contractor.

The facility is owned by the Egyptian Chemical Industries Company (Kima), which in turn is 55% owned by Chemical Industries Holding Company (CIHC), 39% by state agencies, public banks and insurance companies, and 6% by private interests.

In October 2011, Kima awarded the EPC contract to Tecnimont for a new fertiliser complex. The project is expected to cost US$540 million and is scheduled to be commissioned in mid-2014.

The complex will comprise of: a 1,200 tonne per day ammonia plant that will utilise KBR’s purifier technology; a 1,575 tonne per day molten urea plant utilising the pool reactor technology of Stamicarbon of the Netherlands and a 1,575 tonne per day urea granulation plant. The project also entails building the offsites and utilities to support production.

Two more projects are also currently under implementation by subsidiaries of CIHC.

The first is a facility is being implemented by Delta Company for Fertiliser and entails the construction of new complex with a capacity to produce 1,200 tonnes per day of ammonia, 620,000 tonnes per day of urea and 650,000 tonnes per year of nitrates. The project is estimated to cost US$560 million. An EPC conmtract is due to be awarded by late March.

The second project, for which onsite work is due to start by late February, involves refurbishment of the Suez complex of El Nasr Fertilisers, with the aim of increasing its production capacity to 600 tonnes per day of ammonium nitrate, 240 tonnes per day of ammonium sulphate and 135 tonnes per day of nitrate.

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 Europe Oil & Gas Monitor

Top story from 31 January 2012, Week 04 Issue 137

Statoil announces increased gas estimate for Snoehvit

Statoil has upped the reserves of the Snoehvit development by 20 billion cubic metres and is considering a possible increase of 100 bcm as part of an investment plan.

Company spokesman Ola Anders Skauby explained that the reserves boost had resulted from greater recovery owing to subsea compression, new resources proven, additional prospects in the area and potential new volumes tapped on the seabed.

“We have increased our understanding of the reserve and the bedrock in the area. It behaves in a different way than anticipated, which means that we are upgrading our reserve estimate,” he said. “The 100 billion cubic metres are what we see as potential [reserves] in the area that we are using as a basis for an eventual further expansion of capacity,” he added.

The various options on what to do with this extra gas are being considered by the Norwegian major. Earlier this month, Statoil’s CEO Helge Lund told Upstream Online that the choice was between a US$5 billion, 1,000-km export pipeline from the Barents to the existing network in the Norwegian Sea and a new liquefied natural gas (LNG) train for the expansion of Snoehvit.

However, the project’s production director, Oyvind Nilsen, was reported as saying that a gas pipeline might be a more economic option. “A solution with a gas pipeline will be cheaper to develop beyond the capacity we have today, but developing LNG would give us flexibility,” he said. The decision regarding this increase is planned for the second quarter of 2012 and the investment decision for potential LNG capacity expansion is due in 2013.

Snoehvit is the first gas development in the Barents Sea. The partners in the field are: Statoil, operator, with 36.79%; Petoro (30%); Total E&P Norge (18.40%); GDF Suez E&P Norge (12%) and RWE Dea Norge (2.81%).

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 FSU (Former Soviet Union) Oil & Gas Monitor

Top story from 01 February 2012, Week 04 Issue 667

Nabucco rethinks itself

The Nabucco Gas Pipeline International (NGP) consortium is reportedly reassessing its role as a major supplier of natural gas for the European market, now that it is facing stiff competition from a plan unveiled by Turkey and Azerbaijan last December.

The group is now considering proposals for building a pipeline from the Bulgaria-Turkey border to the Central European Gas Hub in Baumgarten an der March, Austria. This link would follow Nabucco’s proposed route through Bulgaria, Romania, Hungary and Austria, while eliminating the component of the project that envisions a new pipe across Turkey, with feeder lines from Georgia and Iraq.

As of press time, the BP-led consortium that is developing Shah Deniz Stage 2 (SD2), the Azeri field that NGP hoped would serve as an initial source of throughput, had not commented on reports of a possible change in Nabucco’s route.

NGP was one of four parties to submit bids for the right to transport 10 bcm per year of SD2 gas last October. The other three came from the backers of the Interconnector Turkey-Greece-Italy (ITGI) project, from the Trans Anatolian Pipeline (TAP) group and from BP, which called for the construction of the South East European Pipeline (SEEP) along a route similar to that of Nabucco. BP and its partners in the Shah Deniz project are expected to award the SD2 gas shipment contract by the middle of this year.

Subsequently, the State Oil Company of Azerbaijan (SOCAR) and Turkey’s national pipeline operator Botas announced that they had formed an 80:20 partnership to build a 10 billion cubic metre per year link across Turkey, stretching from the Georgian border to the Bulgarian border. This conduit, known as the Trans Anatolian Pipeline (TANAP), would have an initial capacity of 16 bcm per year, enough to handle the 6 bcm per year of SD2 gas destined for the Turkish market plus the 10 bcm per year available for delivery to Europe. Ankara said this could be expanded later to carry 30 bcm per year.

Although Turkish officials have said they still support the Nabucco project, the unveiling of TANAP virtually blew NGP out of the water. The 31 bcm per year link, which is now expected to cost around 12 billion euros (US$15.7 billion), may be too much pipeline for the amount of gas available.

To date, the consortium has been unable to secure firm throughput commitments, despite its courting of Azerbaijan and its efforts to line up gas in Iraq and elsewhere.

ITGI and TAP, by contrast, both have projected initial capacities of around 10 bcm per year, which dovetails with BP’s plans for SD2 gas. Likewise, BP’s SEEP project will also have initial throughput of 10 bcm per year.

Together, TANAP and SEEP could remove Nabucco as a feasible project.

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 Global Carbon Emissions Monitor

Top story from 02 February 2012, Week 04 Issue 253

CCS project planned in the Gulf

The Gulf could soon see its first carbon capture and storage (CCS) project after agreement was reached between two Abu Dhabi state-owned companies.

The Abu Dhabi National Oil Company (ADNOC) and Masdar, which trades in renewables, have made “sufficient progress on the commercial principles” to commit to a project to sequester the carbon dioxide (CO2) produced by a steel mill in Mussafah, according to local newspaper The National.

Around 800,000 tonnes of CO2 would be captured from the Emirates Steel factory and store it 50 km away in the Rumaitha oilfield. Neither company commented on a date for the project to begin. A front-end engineering and design (FEED) study for the project was completed in 2010, and the current deal opens the way for tendering to begin.

“It sends a strong signal that carbon capture is not just for the sake of tree-hugging but is a viable commercial activity,” Philip Moss, the former head of carbon trading at Masdar, told the newspaper. Negotiations began in 2009, but had been paralysed by disagreement between the two companies over the price at which ADNOC would sell CO2 to Masdar.

Abu Dhabi plans large-scale use of CO2 to turn Masdar City into a “city of the future”. In the medium term the plan, announced in 2008, envisages a 500-km CO2 pipeline network capable of storing six million tonnes of carbon dioxide per year by 2015. The network may eventually be able to store 30 million tonnes, The National reported.

There are also plans to inject CO2 into oilfields to increase flow rates. Currently, the United Arab Emirates uses natural gas for the purpose, which requires it to import gas from neighbouring Qatar.

Masdar already has a research and development agreement in place with Germany’s Siemens, signed in October 2010. Under the agreement, Siemens has moved its Middle East headquarters to Masdar City, and will work with Masdar on building design and smart grid technology for the city’s low-carbon future.

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 Global LNG Monitor

Top story from 02 February 2012, Week 04 Issue 204

Near-term approval expected for Sinopec’s Beihai terminal plans

Plans at China Petroleum and Chemical Corporation’s (Sinopec) to build a 3 million tonne per year LNG import terminal in southern China are expected to win final state approval in the near future.

“The project has just passed the final evaluations by NDRC [National Development and Reform Commission] experts. The final approval from the government should be soon,” Reuters was told in late January by an anonymous source with direct knowledge of the US$2.8 billion project.

The terminal, to be built in a man-made island off the southwestern coastal city Beihai, is scheduled to start operations around the middle of 2015, slightly behind an earlier plan, and will bring in the LNG from Queensland, Australia.

The Beihai project would supply gas to a dozen cities in Guangxi and two cities in neighbouring Guangdong Province through a planned pipeline grid.

The scheme would be the second LNG import facility for Sinopec, which is building its first terminal in east China’s Qingdao and planning another in Wenzhou, in eastern China.

For a major Chinese LNG import terminal to get final approval, companies need to secure a long-term gas supply agreement and clearance by China’s environmental watchdog. Appraisals by NDRC experts are among the last few key steps before the final green light.

Sinopec is to land-fill a 0.5-square km island off Beihai for the facility, on which it also plans to add more LNG tanks under a Phase 2 plan to boost the total receiving annual capacity to 9 million tonnes per year, said the source.

Sinopec is boosting its natural gas portfolio aggressively through a series of recent acquisitions spanning countries from Australia to North America.

In December, Sinopec agreed to raise its stake in the US$20 billion Australian Pacific LNG joint venture to 25% and to buy more gas from the project under a 20-year supply pact.

China is on a fast track to boost the use of LNG in the coming decades, and aims to triple gas usage by 2020.

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 LatAmOil - Latin America Oil & Gas Monitor

Top story from 31 January 2012, Week 04 Issue 398

Bolivia expropriates Pan American Energy stake in gas block

Bolivia last week expropriated Pan American Energy’s 25% interest in a natural gas block on the grounds that the company, which is backed by the UK’s BP and China’s CNOOC, had not met certain investment requirements in its contract.

Juan Ramon Quintana, Bolivia’s minister of the presidency, said the shares had been transferred by presidential decree to YPFB Chaco, a subsidiary of state-run oil company YPFB.

The block in question is Caipipendi, which is made up of two of the country’s biggest gas fields: Huacaya and Margarita.

Buenos Aires-based Pan American Energy (PAE), in which Argentina’s Bridas is another shareholder, declined to comment on the development. Its partners in the block are Spain’s Repsol and UK-based BG, each with holdings of 37.5%.

The expropriation of the shares is part of “the goal that the state gets involved in the production of gas,” Quintana told reporters in La Paz.

Bolivian Energy Minister Juan Jose Sosa said the expropriation was necessary because without PAE’s investment the production goals of the block would be at risk, which would in turn threaten to scupper the country’s efforts to meet gas export targets to Argentina.

Bolivia has agreed to boost gas deliveries to Argentina to 27.7 million cubic metres per day by 2017, up from about 11 mcm per day in 2011.

The Bolivian government did not specify how much PAE should have invested.

Bolivian media reported that investment in two of the three stages of Caipipendi’s development would cost US$1.6 billion, meaning PAE was required to invest US$400 million in those stages.

The block’s developers, led by Repsol, said they would gradually increase production to 15 mcm per day by 2015 from the current rate of 3.9 mcm per day.

Caipipendi, which is in the southeast lowlands of Bolivia, has proven reserves of nearly 4 trillion cubic feet (113.3 billion cubic metres), yet with more investment could be found to hold 12 tcf (340 bcm).

Repsol, BG and now YPFB Chaco plan to drill four new wells and a processing plant with a capacity of 6 mcm per day of gas to boost output to 14 mcm per day by 2014. Output of 9 mcm per day of gas is due to be achieved by April 1.

Bolivia, which nationalised its oil industry in 2006, wants to raise gas output to 66 mcm per day by 2014 and 80 mcm per day in 2015. Gas output stood at 45 mcm per day in 2011.

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 Middle East Oil & Gas Monitor

Top story from 31 January 2012, Week 04 Issue 360

Samsung lands US$1 billion Iraqi oil infrastructure contract

South Korea’s Samsung Group has landed a near US$1 billion contract from Russia’s Lukoil and Iraq’s South Oil Company for major infrastructure work at the super-giant West Qurna oilfield in southern Iraq.

Government spokesman Ali al-Dabbagh said on January 25 that Samsung would build a central processing facility for oil production in the field.

“Work in the processing facility is expected to finish in 31 months from the start of the work,” Dabbagh was quoted as saying by Dow Jones, following a weekly cabinet meeting.

In June, five companies were reported to be in the frame for the business, including Samsung, Saipem, SNC Lavalin, Punj Lloyd and Globalstroy Engineering.

Lukoil and Norway’s Statoil were awarded a 20-year service contract for West Qurna Phase 2 in Iraq’s second licensing round held in December 2009.

The companies promised to get the southern field pumping at a rate of 1.8 million bpd for payment of US$1.15 a barrel.

Iraq has delayed approving contractors for the scheme, the first phase of which was originally slated for late 2012 but is now on course to start in late 2013, targeting initial production of 400,000 bpd.

Earlier this month, Statoil was reported to be reconsidering its 18.75% stake role in the development over security concerns in the wake of the withdrawal of US forces.

The operating environment in southern Iraq has been tough for foreign operators.

Very costly security precautions are required to protect oil installations against mounting violence.

Corruption and problems in obtaining visas for key personnel have also acted as business prophylactics.

Export constraints and infrastructure bottlenecks have left exports from southern Iraq running at around 1.7 million bpd for much of last year.

When the first of three single point moorings starts up, sales of Basra Light crude from southern Iraq are expected to rise by up to 200,000 bpd in February to 1.9 million bpd.

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 NorthAmOil - North America Oil & Gas Monitor

Top story from 02 February 2012, Week 04 Issue 189

Gulf Coast LNG Export applies to ship LNG from Texas

Moves are under way to export more liquefied natural gas (LNG) from the US. Gulf Coast LNG Export is seeking to export up to 2.8 billion cubic feet (79.3 million cubic metres) per day of LNG from Brownsville, Texas, on the Gulf Coast. This is equivalent to 1.022 trillion cubic feet (28.9 billion cubic metres) or 21.22 million tonnes per year.

The company has filed an application for a federal licence with the US Department of Energy (DoE) to export the LNG. It intends to build a liquefaction facility, storage tanks and a marine export terminal in Brownsville.

Commissioners for the Port of Brownsville recently approved a lease option for Gulf Coast LNG Export for 500 acres (2 square km) of port property. The multi-billion-dollar project could start operating in 2018 if the DoE – and other government agencies – approves the application.

Freeport LNG, in partnership with Macquarie Group, has also applied to export another 1.4 billion cubic feet (39.6 mcm) per day from a proposed facility in Freeport, Texas. This brings the total exports requested by Freeport LNG to 2.8 bcf (79.3 mcm) per day.

Permits are now being sought for 13.73 bcf (388.8 mcm) per day, or 100.23 million tonnes per year, of domestically produced LNG. This would be exported from eight separate facilities.

The US is not yet an exporter of LNG, but could become one from 2016, said the US Energy Information Administration (EIA) in a forecast issued on January 23. In 2016, the country will be exporting an estimated 1.1 billion cubic feet (31.2 mcm) per day, the agency – a division of the DoE – said. By 2019, the total will be 2.2 billion cubic feet (62.3 mcm) per day. More natural gas will be exported to Mexico via natural gas pipelines.

In May 2010, Cheniere Energy won DoE approval for exporting LNG. It intends to become the first company to export LNG from the continental US. Since it acquired DoE approval, Cheniere has agreed to sell 3.5 million tonnes per year of LNG through a subsidiary to GAIL of India. The LNG will be processed in Louisiana, on the Gulf Coast.

In October 2011, Sabine Pass also announced a US$8 billion deal with a subsidiary of UK-headquartered BG Group for the purchase of 3.5 million tonnes per year of LNG over 20 years. A month later, Sabine Pass Liquefaction agreed to sell 3.5 million tonnes per year of LNG to a subsidiary of Spain’s Gas Natural Fenosa.

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 Unconventional Oil & Gas Monitor

Top story from 30 January 2012, Week 04 Issue 91

China allows US firms access to its shale gas

A new Chinese law approves shale gas an “an independent mining resource,” Xinhua News Agency reported, giving US firms carte blanche to start developing shale gas in the country. According to Reuters, China’s Ministry of Land and Resources took this step in order to bring more firms into the sector, which is currently dominated by large Chinese companies.

The Ministry had also announced in 2011 that it was planning a second round of shale gas auctions for the beginning of this year, Xinhua reported. While foreign firms will not be allowed to take part in the bidding, they will be able to partner with Chinese companies that win the tenders. The move to include foreign firms could have great repercussions for these companies, considering China’s vast shale gas resources. According to the US Energy Information Administration (EIA), China has 36.1 trillion cubic metres worth of technically recoverable shale gas, compared with 24.4 trillion cubic metres in the US.

Up until now, shale gas exploration and production rights in China have been awarded to Sinopec Group, China National Offshore Oil Corp. (CNOOC) and China National Petroleum Corp. (CNPC). Earlier this month, it was reported that CNOOC had begun drilling its first shale gas project in the country. However, China has not yet begun commercial shale production.

According to Reuters, China hopes to produce 6.49 billion cubic metres of shale gas by 2015. By 2020, the country will be targeting 79.8 billion cubic metres of shale gas production – almost a ten-fold increase in five years. China only uses clean-burning natural gas for 4% of its energy supply, compared with more than 20% for most of the modern world, and is already the third largest consumer of natural gas in the world after the US and Russia. It has a goal of getting to the point where natural gas accounts for 10% of its energy supply by 2020.

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 AsiaElec - Asia Power Monitor

Top story from 31 January 2012, Week 04 Issue 142

China edges past Japan as leading coal importer

China overtook Japan last year to become the world’s biggest importer of coal, government data showed.

During 2011, China imported 182.4 million tonnes of coal, marking a 10.8% increase on the previous year, Chinese government data revealed.

Japan, meanwhile, saw its imports of coal slip by 5.1% to 175.2 million tonnes, according to Customs figures.

Japan’s coal demand was hit last year after March’s earthquake damaged some coal-fired thermal power plants (TPPs). Steelmakers also cut back on production, weakening demand for coking coal.

Japan had been the world’s biggest importer of coal since at least 1975, according to the International Energy Agency’s (IEA) Coal Information report.

China will probably hold on to the top spot this year as well, according to Hirofumi Furukawa, an expert at the Japan Coal Energy Centre.

“China’s domestic production will be managed by the government,” he told Reuters. “The costs are rising and when it comes to competition, foreign coal is cheaper, so there will be pressure for imports,” he explained.

“Some say it will rise to 200 million tonnes [in 2012],” he added, referring to Chinese coal demand. “Japan, on the other hand, is expected to see steady imports [in 2012].”

Japan’s thermal coal imports edged down 0.4% last year to 101.2 million tonnes, mostly because of earthquake damage to coal-fired TPPs along the country’s northeast coast.

In January to November, Japan’s coking coal imports took an even bigger hit, declining 9.4% year-on-year to 63.5 million tonnes, according to Reuters calculations.

The effects of last year’s magnitude 9 earthquake continue to be felt, with consumption of thermal coal in the financial year to the end of March 2012 seen as dropping by 0.2%, the Institute of Energy Economics, Japan (IEEJ) forecast in December.

If shuttered nuclear power plants (NPPs) are not restarted, however, thermal coal demand in Japan could leap by 8.3% in the financial year ending March 2013, the IEEJ predicted. If reactors are restarted this year, thermal coal demand in the 2012/13 financial year could decline by 7.2%, it added.

China’s coal consumption, meanwhile, should remain strong as new coal-fired TPPs come on line. The government’s push to urbanise should boost demand from the cement industry.

However, a Reuters poll in December foresaw Chinese coal imports growing at a slower pace this year as domestic coal production grows and demand moderates.

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 Energo - CEE/FSU Power Monitor

Top story from 01 February 2012, Week 04 Issue 598

Transelectrica to invest US$757 million

Romanian grid company Transelectrica (TEL) is to make investments totalling around 2.5 billion lei (US$757 million) in the coming three years.

This emerged from the report of a TEL forecast covering the years 2012-2014 carried by the heavyweight Bucharest daily Ziarul financiar (ZF) last week.

This means that TEL will step up the pace of its investments, it seems: investments envisaged in 2012 come to 782 million lei (US$236 million), a 49% rise on the level achieved in 2011, ZF reported.

At the top of the list of projects for the next three years is the 224 million lei (US$68 million) first stage of the upgrading to 400 kV of the existing transmission line that connects the Iron Gates on the Danube to Arad near the Hungarian border in western Romania via Resita, Timisoara and Sacalaz.

Linked to this is a 102 million lei (US$31 million) investment in a line linking the 400-kV line at Resita with that of neighbouring Serbia.

In the country’s east, 162 million lei (US$49 million) is earmarked for a project linking the Romanian-Bulgarian Isaccea-Varna and Isaccea-Dobrudzha interconnectors to TEL’s 400-kV Medgidia Sud substation.

As to substations, TEL intends to spend 151 million lei (US$46 million) on refurbishing the one at Tulcea West, while ZF reports that “tens of millions” of lei are to be devoted to upgrading or modernising the Turnu Severin East, Campia Turzii, Dornesti, Bradu and Suceava substations.

Other investments will include 126 million lei (US$38 million) in measures to prevent or manage incidents and in system security and 132 million lei (US$40 million) in new grid connections.

Rather more than half (1.3 billion lei, US$393 million) of the planned investments will be covered by TEL from its own resources, including connection fees and EU grant finance.

The remaining 1.2 billion lei (US$363 million) will need to come from banks.

This will add considerably to TEL’s debts, which, as ZF points out, totalled 1.68 billion lei (US$508 million) at the end of September 2011.

The plan provides for repayment of 523 million lei (US$158 million) of these over the next three years.

TEL thinks it will have made net profits of 25 million lei (US$7.6 million) in 2011 on a turnover of 2.78 billion lei (US$842 million).

Some improvement, but not very much, is anticipated in 2012 and the two following years.

Transelectrica is currently majority-owned by the Romanian state: the economy ministry holds 73.69% of shares, while 13.5% of the rest is owned by Fondul Proprietatea (the Property Fund), a vehicle set up to provide compensation to Romanians whose property was confiscated under the communist regime.

The remaining 12.81% is owned by numerous local and foreign shareholders.

Flotation of another 15% of the state’s share in TEL is due in late February. The proceeds are expected to be around 40 million lei (US$12 million).

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 Renewable Energy Monitor

Top story from 02 February 2012, Week 04 Issue 293

Clean Energy Index down nearly 45% in 2011

Companies in the renewables and clean technology sectors have suffered in global stock markets over the past 12 months as the economic situation in Europe has deteriorated.

The trend has been starkly illustrated by the latest figures from Standard & Poors, whose S&P Global Clean Energy Index, which tracks the performance of 30 of the most liquid and tradable global clean energy companies, fell by nearly 44.5% during 2011.

One of the challenges involved in addressing the market is defining the companies that constitute the “alternative energy” sector. It covers global utilities with renewables capacity, developers, technology companies and even carbon credit companies.

Yet aside from the weak economic environment, the sector has faced a series of challenges in the eyes of investors. Heavy investment has led to overcapacity, especially in the solar sector. Many countries have enacted austerity policies in order to address the economic challenge, which has proved detrimental to technologies that are not yet cost-competitive with alternatives.

Confusion over legislation regarding emissions reduction has hit private sector investment and simultaneously a failure to achieve clarity on how emissions reductions should be achieved under an international climate change agreement has further muddied the waters.

Last year was a difficult one for many listed companies. Nevertheless, long-term value drivers for the alternative energy sector remain strong.

Corporate strategies are likely to encourage further focus on cleantech and renewables. Economic growth is a key goal for most countries but developing nations need increasing amounts of energy and raw materials and managing the cost of inputs is likely to become an ever more important factor for many companies. The need for greater efficiency is likely to drive the market.

As a sector, the alternative energy market may continue to prove to be a difficult investment in 2012. There are likely to be individual success stories however, as different sub-sectors face different challenges. There is certainly no lack of overall investment in the sector, with global investment up 5% to US$250 billion. Venture capital and corporate investment rose 13% to US$9 billion, while M&A grew even more strongly, up 153% to US$41 billion.

Aversion to risk will have contributed significantly to the poor performance of the Clean Energy index and that is unlikely to change in the near future.

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