Top story from 21 February 2012, Week 07 Issue 427

Cote d’Ivoire dishes out blocks

Three ultra-deepwater blocks offshore Cote d’Ivoire have been awarded to Total, Anadarko Petroleum and Canadian Natural Resources Ltd (CNRL).

Total, on February 17, announced it had signed production-sharing agreements (PSAs) with the Ivorian government and the country’s state-owned Petroci.

The French company is to operate the CI-514 block with a 54% stake, while CNRL will have 36% and Petroci 10%. Anadarko is to operate the other two blocks, CI-515 and CI-516, with a 45% stake, while Total has 45% and Petroci 10%.

The blocks are around 100 km offshore and cover 3,200 square km, Total said, with water depths of 2,000-3,000 metres.

During the first three-year period, the companies are required to acquire 3-D seismic on the whole acreage and drill one well on each block.

Total’s vice president for exploration, Marc Blaizot, said work in the ultra-deepwater was an area in “which our expertise is globally recognised. The so-called Abrupt Margin theme that we will be exploring in this acreage is a core growth driver for the future. In particular, we are targeting the same theme in exploration licences in French Guiana, where a promising discovery has already been made, and in Mauritania.”

The French company also operates the CI-100 block with a 60% stake, with the remainder held by Yam’s Petroleum and Petroci. The licence covers 2,000 square km in water depths of 1,500-3,100 metres. Seismic began at the end of 2011 and Total plans to drill a first exploration well there by the end of the year.

Anadarko, which has played a pivotal role in opening up this area through its exploration in Ghana’s offshore, spudded a well in January offshore Cote d’Ivoire. The Kosrou well is targeting a prospect similar to Ghana’s Jubilee and this will be followed by a well on the Paon prospect. Although asked for additional information, Anadarko had not responded at the time of going to press.

CNRL has interests in the Baobab and Espoir fields, offshore Cote d’Ivoire.

Top story from 16 February 2012, Week 06 Issue 381

ENN says it will stand by its offer for China Gas

ENN Energy Holdings last week defended its bid for Hong Kong-listed China Gas Holdings, saying that the US$2.2 billion offer submitted jointly with Sinopec was fair.

China Gas has protested against the takeover attempt, complaining that it had not sought a deal with ENN and Sinopec.

It has described the bid as “wholly unsolicited [and] opportunistic.” It has also asserted that the two companies’ offer does not “reflect [the] fundamental value” of the company.

ENN’s executive director, Wang Dongzhi, disagreed, saying that his firm did not intend to submit a higher bid. “We still think the price is very reasonable,” the Hong Kong Economic Journal quoted him as saying. “The bid price was decided after very careful consideration.”

Wang also said he expected ENN’s shareholders to approve plans for taking control of China Gas at their next meeting, which will be held before the end of this month.

The executive director was speaking shortly after representatives of the ENN-Sinopec alliance spoke publicly about their companies’ plans for China Gas. If the takeover attempt is successful, they said, the partners will make no significant changes to China Gas’ staff. There will be some board-level changes, they explained, but most employees will continue to have the same responsibilities.

They did not comment on discussions between the partners and China Gas. However, they did say that ENN and Sinopec would continue to seek the opportunity to conduct talks with the gas distributor’s board of directors.

The partners made an unsolicited cash bid for China Gas in December 2011, offering to pay for the latter company’s stock at a rate of HK$3.5 (US$0.45) per share. They also said at that time that they were ready to spend as much as US$16.7 billion to acquire all of the distributor’s outstanding shares.

China Gas was quick to reject the offer. Earlier this month, it said that around 4,000 of its employees had signed petitions voicing opposition to a takeover by ENN and Sinopec.

China Gas is a key player in China’s gas sector. It is primarily focused on municipal gas distribution but is also involved in a number of other projects. According to the company’s website: “China Gas owns a total of 123 city piped gas projects in 19 provinces, autonomous regions and directly-administered cities, eight natural gas pipeline transmission projects, one natural gas development project [and] 91 CNG vehicle refilling stations, as well as 37 [liquid petroleum gas] LPG distribution projects.”

Top story from 22 February 2012, Week 07 Issue 44

Tender to be launched for Duqm FEED package

Abu Dhabi-based International Petroleum Investment Company (IPIC) along with Oman Oil Company (OOC) are aiming to issue a tender by March 15 for a contract to prepare the front-end engineering and design (FEED) package for the proposed Duqm refinery and petrochemical complex in eastern Oman.

Companies planning to participate in the tender include: Kellogg Brown and Root (KBR), the Shaw Group, Jacobs Engineering and Fluor Corp., all of the US; Australia’s WorleyParsons; Italy’s Snamprogetti; Paris-based Technip and Japan’s JGC Corp.

Estimated to cost US$5 billion, the 350,000 barrel per day refinery and petrochemical complex is expected to be commissioned by late 2015 or early 2016.

A contract has already been awarded to US-based KBC Advanced Technologies to carry out a detailed feasibility study for the proposed complex, while WorleyParsons has already prepared an initial master plan.

The KBC study has been carried out in two parts: a market study on demand for refined and petrochemical products in the Gulf, Europe and Asia, and a technical and commercial analysis of building a new refinery.

“The client [OOC and IPIC team] is looking at some strategic options,” a Muscat-based industry executive told Downstream MEA. He added: “While the refined products will be sold to consumers in the Gulf and in Asia, the petrochemical products [olefins and aromatics] will be marketed fully in Asia. OOC is aiming to utilise heavy crude produced by [Petroleum Development Oman (PDO)] as feedstock for the proposed refinery. The configuration of the facility will be important, as there will be the need to install additional cokers.”

In October 2009, OOC and IPIC formally signed a memorandum of understanding (MOU) to build the refinery and petrochemical complex proposing to build a grassroots refinery and polypropylene (PP) complex.

Top story from 21 February 2012, Week 07 Issue 140

ITGI out of the running for SD2

The Shah Deniz consortium has excluded the Interconnector Turkey-Greece-Italy (ITGI) pipeline project from the potential routes for exporting gas from Azerbaijan.

The consortium will “no longer” consider the pipeline, according to one of its representatives – which is led by the State Oil Company of Azerbaijan Republic (SOCAR) – who was quoted by Interfax-Azerbaijan on February 20.

On the same day, a spokesman for consortium member BP told Dow Jones Newswires: “The SOCAR-led negotiating team has made the decision to undertake exclusive negotiations with [the Trans Adriatic Pipeline (TAP)] on a southern pipeline route through Italy … [this means that it] will not be considered further.”

The project, whose partners are Greece’s Public Gas Corp. (DEPA) and Italy’s Edison, was one of four projects vying to export gas from Phase II of development of the major Shah Deniz gas field to Europe.

Interfax quoted its source as saying: “Two of these projects – ITGI and TAP ... The ITGI project is no longer under consideration, while the TAP project is still on the agenda.”

The TAP will, therefore, only be negotiating to carry the gas from the Caspian to Italy.

It is the first option to have been taken off the table in the SD consortium’s progress towards making its long-awaited decision, and is an important step.

The consortium must now narrow down the other remaining options – the EU-backed Nabucco project and the South East Europe Pipeline (SEEP), backed by BP. These are both designed to carry the gas to Central Europe.

The BP spokesman was quoted as saying: “Once that is done, it will be possible to make a decision between a northern [to Central Europe] or southern [to Italy] pipeline route.”

The SEEP project would pass through Bulgaria, Romania and Hungary to Croatia, while Nabucco would cross Bulgaria, Romania and Hungary to the Baumgarten gas hub in Austria.

Opening up the southern gas corridor is high on the agenda of the European Union as it seeks to diversify supply and lessen dependence on Russia and thus Gazprom.

Top story from 22 February 2012, Week 07 Issue 670

Gazprom extends 10% price cut to European, Turkish clients

Russia’s natural gas monopoly Gazprom has reduced the price of gas delivered under long-term contracts to customers in Europe and Turkey by 10%, The Financial Times reported last week.

“Our partners asked us to revise our prices ……. What we did [was to] correct the parameters of our formula, which led to a relative price reduction of 10% on average.” Gazprom’s deputy CEO Alexander Medvedev commented.

Medvedev stressed that the new price would “ensure that Russian gas remains competitive.”

The FT also quoted him as saying that concessions were made after negotiations with GDF Suez (France), Wingas (Germany), SPP (Slovakia) and Botas (Turkey).

According to Gazprom’s latest quarterly report, published earlier this month, the holding continues to review its contracts with European clients. The company also intends to hold commercial consultations with RWE Transgas (Germany), Shell Energy Europe (UK/Netherlands), E.ON Ruhrgas (Germany), Eni (Italy), GWH Gashandel (Austria), Centrex (registered in Cyprus and active in Austria), EGL (Italy/Switzerland), GasTerra (Netherlands), DONG (Denmark) and PGNiG (Poland).

In January, Medvedev said that gas price cuts would not be extended to the European energy companies that filed suit against Gazprom in the Stockholm Arbitration Tribunal last year. These firms – including PGNiG, E.ON and RWE, as well as Edison of Italy – were seeking a ruling that would require the Russian giant to use spot market prices instead of relying solely on a formula linked to world crude oil prices.

According to sources close to the negotiation process, Gazprom is trying to curb further increases by including a spot market price component in its contracts with EU customers. It hopes that amending its pricing formulae in this fashion will allow it to reach agreement with other European customers outside the arbitration process.

To date, Edison is the only company to have succeeded in securing lower prices after seeking arbitration.

Offer to Ukraine

In related news, Moscow has also offered Kiev a 10% discount on gas supplies.

Russian authorities said they would be willing to authorize a price cut provided that Kiev drops its plans to cut gas imports drastically this year, Kommersant Ukraine newspaper reported on Monday, citing a source close to the talks.

This discount rate would be in line with the adjustments Moscow has agreed to make for several European companies.

Top story from 16 February 2012, Week 06 Issue 255

Hokuriku Electric’s emissions to soar in FY2011

Hokuriku Electric Power Co. said it expected its carbon dioxide (CO2) emissions to jump 44% to around 18 million tonnes in the current fiscal year ending on March 31, making it difficult for the Japanese utility to achieve its emissions intensity target.

Hokuriku Electric said it anticipated its electricity sales totalling 28.7 billion kWh in fiscal 2011, down 2.7% from fiscal 2010. As a result, the company’s CO2 emissions intensity – emissions per 1 kWh of electricity sold – is projected to stand at around 0.6 kg of CO2 per kWh in fiscal 2011.

Hokuriku Electric, based in Toyama City, Toyama Prefecture, in central Japan, is the country’s eighth largest electricity utility by electricity sales volume.

The firm expects the sharp rise in CO2 emissions in fiscal 2011, as it has ramped up thermal power generation to make up for lost output at its sole nuclear power plant (NPP), which has been shut since March 2011.

The Japanese electric power industry has no target for cutting CO2 emissions in terms of total volume. Instead, it set a target of reducing its CO2 emissions intensity by 20% from 0.417 kg of CO2 per kWh in fiscal 1990 to 0.34 kg of CO2 per kWh on average between fiscal 2008 and 2012.

In line with the industry target, Hokuriku Electric set its own target of lowering its CO2 emissions intensity by 20% to 0.32 kg of CO2 per kWh on average between fiscal 2008 and 2012 from 0.395 kg of CO2 per kWh in fiscal 1990.

To achieve the CO2 emissions intensity target, Hokuriku Electric has so far used some of the carbon credits purchased utilising the mechanisms of the Kyoto protocol. In fiscal 2010, the firm used 5.88 million Kyoto credits.

Between fiscal 2008 and 2010, the company’s CO2 emissions intensity reflecting the use of Kyoto credits totalling 9.51 million averaged 0.337 kg of CO2 per kWh, still higher than the target of 0.32 kg of CO2 per kWh.

Hokuriku Electric said that it would continue to make efforts to achieve the CO2 emissions intensity target for the fiscal 2008-2012 period. It said, however, that it was very difficult for the company to achieve the target on an annual basis in fiscal 2011.

The firm should incur a record net loss of around 10 billion yen (US$128 million) in fiscal 2011 owing largely to sharply higher fuel costs for thermal power generation.

Given the extremely difficult financial conditions, the company said it had yet to decide whether to use any Kyoto credits in fiscal 2011, despite the anticipated sharp rise in CO2 emissions.

Like other Japanese electric power companies, Hokuriku Electric has not disclosed how many carbon credits it has so far purchased utilising the Kyoto mechanisms.

Markey sets sights on LNG exports

Representative Ed Markey has proposed a bill that would halt the construction of liquefied natural gas (LNG) terminals until at least 2025. The legislation comes as the US’ shale gas estimates have been cut back and concerns grow that exports would lead to higher domestic prices.

The congressman’s North America Natural Gas Security and Consumer Protection Act would require the Federal Energy Regulatory Commission (FERC) to refuse applications for the construction of export facilities until 2025. This would cover both building new plants or converting existing import terminals.

The American Public Gas Association (APGA) issued an open letter on February 14 expressing support for Markey’s legislation. The group, which is the association of local distribution systems, backed the representative, saying he was trying to protect domestic consumers from price increases.

Nine LNG applications have been filed with the US Department of Energy, as of February 10, with a total capacity of 13.74 billion cubic feet (389 million cubic metres) per day. The US’ production in 2011 was around 66 bcf (1.87 billion cubic metres) per day.

The Energy Information Administration (EIA) issued projections on the likely impact of gas exports on January 19. The report concluded that there would be an impact on consumer spending on natural gas and power. On average, from 2015 to 2035, gas bills would rise by 3-9% – against a situation with no exports – while electricity spending would increase by 1-3%. The EIA’s predictions focused on exports of 6 bcf (170 mcm) per and 12 bcf (340 mcm) per day.

The agency’s conclusions differ from a Deloitte report, published in late 2011. Deloitte, using the lower case assumed by the EIA, said local gas prices would rise from 2016-35 by only 1.7%, although with a higher impact on Henry Hub, owing to its proximity to the export terminals.

The scale of “total LNG exports is substantial on its own, but not very significant relative to the entire US resource base or total US demand,” Deloitte said.

The EIA also reduced its recoverable shale gas resource estimate in January, cutting it from 827 trillion cubic feet (23.4 trillion cubic metres) to 482 tcf (13.7 tcm), largely as a result of more data from the Marcellus. The agency, setting out early conclusions from its annual energy outlook, also predicted the US would become a net exporter of LNG in 2016, shipping 1.1 bcf (31 mcm) per day, growing by another 1.1 bcf per day in 2019.

Top story from 21 February 2012, Week 07 Issue 401

Pacific Rubiales strikes gas in Magdalena Province

Pacific Rubiales Energy has announced the discovery of natural gas and concentrates in an exploratory well in Colombia’s northern province of Magdalena. The news was released one month after the company drilled to a total depth of 7,210 feet (2,200 metres) at the site.

According to the February 15 statement, “the petrophysical evaluation showed a total of 40 feet [12 metres] of net pay, with average 20% porosity.” At a 0.5-inch (13-mm) choke, the company proclaimed: “Cotorra-1X reached a maximum gas flow rate of 7.5 million cubic feet [212,400 cubic metres] per day and 370 barrels per day 56 degrees API condensate.” The evaluation looked at two intervals of the deeper pay zone and left “overlying pay zones untested” for the moment.

Success at the Cotorra-1X well represents the Canadian company’s second win in the Lower Magdalena Basin’s Guama block, in which the company is operator and has a 100% interest.

Pacific Rubiales’ CEO, Ronald Pantin, linked the good news to the company’s plan to start a liquefied natural gas (LNG) project in Colombia within two years “This is an important exploration discovery for Pacific Rubiales and demonstrates the potential of both the Guama block and Lower Magdalena Basin, where the company has a large exploration acreage position and is looking to increase its gas reserves to support its initiative to develop an LNG export market in the future,” he said.

Tucked on the end of the statement, the company also released the bad news that it had been forced to plug and abandon the Apamate-2X exploration well in the La Creciente block after it “failed to test hydrocarbon flow at economic rates”.

The abandonment could cut down Pacific’s reported probable reserves of 9.38 million boe, according to the brokerage InterBolsa, quoted by FoxBusiness on February 15. For the brokerage, the negative impact of Apamate-2X more than offset the success concerning Cotorra-1X, because InterBolsa said it considered “that the first had a higher potential for production and reserves.”

Despite the mixed news, traders responded positively and added 1% to Pacific’s value the morning after the announcement.

Pacific produces 233,000 bpd of crude in Colombia and has become the largest independent producer in the country, where it operates the huge Rubiales and Piriri fields with state-operator Ecopetrol. The multinational plans to invest US$1.2 billion in Colombia during 2012, and also operates in Peru and Guatemala.

Top story from 21 February 2012, Week 07 Issue 363

Abu Dhabi crude oil pipeline facing yet more delays

The strategic Abu Dhabi-Fujairah crude oil pipeline is once again facing delays, with the facility not expected to be operational before November.

Under the original plan, the strategic facility was due to be working in January 2011. However, it faced delays owing to issues related to supplies of line pipe and the inability of the main engineering, procurement and construction (EPC) contractor, China Petroleum Engineering and Construction Corporation (CPECC), to mobilise on site.

A commissioning date of June 2012 was later set but this too has now been pushed back.

“A vast majority of the work has been completed, but there are still several technical problems that will delay start-up,” an Abu Dhabi-based industry executive told MEOG on condition of anonymity.

“There are a number of problems with the Chinese-built pipeline, including the absence of sufficient pumping stations, which delayed commissioning and came to light during a test period. Also, the pipeline does not meet the UAE’s high specifications,” the executive added.

He commented that the Chinese contractors were more familiar with specifications for pipelines in Africa, which do not match the same international criteria applied by the UAE.

The 450-kilometre, 36-inch diameter pipeline, which is being built at an estimated cost of US$3.3 billion, will run from Habshan in western Abu Dhabi to Fujairah on the UAE’s east coast.

It will have the capacity to transport 1.5-1.8 million barrels per day (bpd) of crude oil and will account for 70% of Abu Dhabi’s total exports.

The pipeline is being built for Abu Dhabi to have direct access to markets, bypassing the congested and vulnerable Strait of Hormuz.

The project also includes building eight 1 million barrel storage tanks at Fujairah and two in Habshan, giving a total storage capacity of 10 million barrels.

Two main oil terminal loading facilities consisting of two pumping stations each with a loading capacity of 80,000 barrels per hour have also been built.

The pipeline is being constructed by Abu Dhabi-based International Petroleum Investment Company.

Abu Dhabi currently produces around 2.5 million bpd and relies almost exclusively on its Gulf ports to export its crude.

The commissioning of the pipeline comes as several Arab producers in the Gulf have expressed concerns about the security of their oil exports through the Strait of Hormuz following recent threats by Iran to shut down the waterway in response to sanctions targeting its oil exports, all of which pass through the chokepoint.

Top story from 16 February 2012, Week 06 Issue 191

Chesapeake plans up to US$12 billion of asset sales

Chesapeake Energy has set out plans to balance its books as weak gas prices and high debt continue to weigh down on it. The company, on February 13, put out details of its financial plan, which included a target of achieving US$10-12 billion of asset sales this year.

Selling down assets should allow Chesapeake, it said, to balance its spending.

Two deals – worth around US$2 billion in total – are to be completed within the next two months, on its Texas Panhandle Granite Wash area and a stake in the Cleveland and Tonkawa plays, in Oklahoma’s Ellis and Roger Mills counties. The Granite Wash deal is a volumetric production payment (VPP) deal, while the second is structured similarly to the recent Utica transaction.

The company is also seeking joint ventures in its Mississippi Lime and Permian Basin plays. Chesapeake said it was open to selling its entire stake in the latter area, if it received a “compelling offer.” The firm has acreage in the Bone Spring, Avalon, Wolfcamp and Wolfberry plays of the Permian Basin. Deals on the Mississippi Lime and Permian Basin could raise Chesapeake US$6-8 billion in 2012. These deals should be completed by the end of the third quarter.

Jefferies Research said the Permian Basin asset could achieve a value of US$5-6 billion, but that as a result of this there would fewer potential buyers – because of the high price tag. The analyst report went on to say a Mississippi Lime joint venture would “generate less than US$1 billion” for Chesapeake.

Other sales planned for the year include midstream, service company and other holdings, adding around US$2 billion.

The sales are “substantially in excess” of Chesapeake’s operating cash flow and will allow it to “achieve its previously announced debt reduction goals, while providing additional financial strength during this current period of low US natural gas prices.”

The same day, the company also offered US$1.3 billion of senior notes with an interest rate of 6.775%, due in 2019. These are to be used to refinance shorter-term debt. Chesapeake has a target of reducing debt to US$9.5 billion by the end of 2012.

A note from FBR Capital Markets said the plan was a “step in the right direction” to address debt concerns but that investors would wait for signs of progress on this front and would want to see evidence that assets retained were sufficiently high-quality. FBR said concerns would also continue on Chesapeake’s unhedged natural gas and natural gas liquids (NGLs) production.

Top story from 20 February 2012, Week 07 Issue 94

Halliburton, Petronas ink shale deal

US oilfield services giant Halliburton has signed an agreement with a division of Malaysia’s state-owned energy firm Petronas that will see the two companies partner on a number of global shale projects.

In a statement Halliburton said that the contract would enable Petronas Carigali, the company’s upstream wing, to shorten its in-house capability development by leveraging on Halliburton’s technology and experience in the North American shale industry.

In addition, Halliburton will work with Petronas to set up a Shale Technical Centre of Excellence in Malaysia’s capital, Kuala Lumpur.

“One of the cornerstones of Halliburton’s strategy is to maintain leadership in unconventional plays,” Halliburton’s senior vice president of Global Business Development and Marketing, Jeff Miller, said.

“Expanding into the Asia-Pacific market and providing the same quality level of service we already provide in North America fits into that strategy,” Miller said.

Halliburton employs more than 5,600 people in the Asia-Pacific region. Following the recent slowdown in the US shale sector, largely caused by low gas prices in North America, the company has been increasingly keen to export its expertise overseas, with Asia a particular point of focus.

Halliburton already provides unconventional exploration services in Latin American and European countries such as Poland, which holds an estimated 187 trillion cubic feet (5.3 trillion cubic metres) of recoverable shale gas reserves. The firm is the second largest player in the oilfield services segment after world leader Schlumberger.

In June 2011, Petronas paid US$1.1 billion for a 50% share in three Canadian shale gas fields in an attempt to keep up with Asian rivals such as China, South Korea and India, which have all invested heavily in the North American unconventional energy sector. China has the world’s largest estimated shale gas reserves of 1,275 tcf (36.1 tcm).

Top story from 21 February 2012, Week 07 Issue 145

TEPCO may sell Australian TPP stake

Beleaguered Tokyo Electric Power Co. (TEPCO) is in talks to sell its 32.54% stake in a large coal-fired thermal power plant (TPP) project in the Australian state of Victoria to AGL Energy Ltd., a major local power and gas retailer.

The largest Japanese electricity utility is reeling from the nuclear crisis at its Fukushima No.1 nuclear power plant (NPP), which was triggered by the devastating earthquake and tsunami that hit the northeastern part of the country on March 11 last year.

AGL Energy issued a statement last week confirming that it was in talks on its possible purchase of TEPCO’s 32.54% stake in Great Energy Alliance Corporation Pty Ltd. (GEAC), owner of the Loy Yang A TPP.

“Negotiations are incomplete and there is no certainty that a transaction will proceed,” the Australian company said.

GEAC also owns 1.6 billion tonnes of coal resources. AGL Energy is already GEAC’s largest shareholder along with TEPCO and holds a 32.54% stake.

The 2,200-MW Loy Yang A TPP is Victoria’s largest, supplying about one-third of local electricity needs.

The Australian Financial Review reported that as AGL Energy was looking to buy TEPCO’s stake at a heavy discount, the deal was expected to be worth only A$145 million (US$154.9 million).

AGL Energy currently values its 32.54% GEAC stake at A$326.7 million, according to the newspaper.

TEPCO has already been considering selling some of its TPPs in Japan as part of efforts to cover the massive compensation payments arising from the nuclear crisis.

TEPCO unveiled an action plan for streamlining its management on December 9. Under the action plan, the company said it would consider selling some of its TPPs and would also shelve plans to build new ones, in principle.

TEPCO is expected to increase its purchases of electricity from other power companies to cover an envisaged reduction in electricity generated at its own power plants.

Top story from 22 February 2012, Week 07 Issue 601

Czechs plan eco-friendly overhaul to Varna TPP

Czech energy giant CEZ is to spend 100 million euros (US$130 million) to modernise its thermal power plant (TPP) in Varna, Bulgaria, to make the facility more environmentally friendly.

The company is to upgrade units four, five and six at the Varna TPP to reduce emissions and extend the life of the overall facility until 2030, Petr Dokladal, chairman of the Varna TPP supervisory board, told the Bulgarian media last week. Unit three might also be modernised.

CEZ has prioritised emissions reductions, as the European Union (EU) wants member states to reduce their carbon footprints.

The city of Varna, meanwhile, joined roughly 500 other cities in 2010 to sign an EU-backed agreement to slash CO2 emissions by over 20% within the decade.

To finance the Varna modernisation, Dokladal said that CEZ, which has stalled many of its regional expansion plans because of the global financial crisis, would seek co-investors. A tender is to be launched in July.

Located in southeastern Bulgaria near the Black Sea, the Varna TPP is the second largest TPP in both Bulgaria and the larger Balkan region. The 1,260-MW facility burns coal in its six mono-blocks.

One of the largest listed companies in Central and Eastern Europe, CEZ bought a full stake in the plant in 2006.

Last October, the company said it had no plans to sell the Varna TPP after Russian energy export giant Gazprom expressed interest in buying power assets in several European countries, Bulgaria included.

CEZ has had to abandon expansion plans for Varna. In 2009 the company announced plans to build an 880-MW gas-fired power unit there, but it dropped the project last year because the power generated would be too expensive owing to high natural gas prices.

Though just beginning, 2012 is proving to be a good year for the Bulgarian energy industry. In January, a Bulgarian subsidiary of Russia’s LUKoil announced a US$1.5 billion investment to build a hydrocracking plant in Burgas, on the Black Sea, to process petroleum waste.

Top story from 16 February 2012, Week 06 Issue 295

Swiss cut solar subsidies

The Swiss government has announced a 10% cut in solar subsidies, to come into force from March 1, 2012, with another possibly on the way later in the year.

The Federal Department for the Environment, Transport, Energy and Communication announced the cut on February 1, which will be introduced in addition to an automatic 8% cut that came into force on January 1.

According to German news outlet IWR, the new feed-in tariff (FiT) rates for solar power range from 48.8 rappen (US0.53) per kWh for smaller, integrated solar units, to 28.8 rappen (US$0.31) for large-scale solar plants with an independent grid connection.

The ministry cited low module prices as a reason for the decision, because this had led to lower installation costs for solar plants, as well as falling maintenance costs. The decision will not affect solar installations that have already received government approval, even if they are not commissioned by the March 1 deadline. More cuts may take place later in the year. “As a result of the great uncertainties surrounding the future development of module prices, a further examination of photovoltaic feed-in tariff rates is planned for mid-2012,” the ministry said in a statement.

The ministry also decided to widen the FiT band for wind farms, which now ranges from 13.5 rappen (US$0.15) per kWh to 21.5 rappen (US$0.24). The system for wind turbines uses similar size and integration guidelines to band installations as those used for solar plants. “The examination found that the current feed-in tariff rates were too high for locations with optimal wind conditions but did not cover the costs of locations with wind conditions that are merely suitable,” the ministry said.

Some biomass plants will see a rise in their FiT rates from March 1, after the ministry decided that it was justified by the rising cost of firewood, especially for plants under 5 MW. Some FiTs will remain at their current level, while others will rise by up to 4.5 rappen (US$0.05) per kWh, chiefly for smaller installations.